FORM 10-Q
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For The Quarterly Period Ended June 30, 1996
Commission file number 1-1910
BALTIMORE GAS AND ELECTRIC COMPANY
-----------------------------------------------------------------
(Exact name of registrant as specified in its charter)
Maryland 52-0280210
-----------------------------------------------------------------
(State of incorporation) (IRS Employer Identification No.)
39 W. Lexington Street Baltimore, Maryland 21201
-----------------------------------------------------------------
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code 410-783-5920
Not Applicable
-----------------------------------------------------------------
(Former name, former address and former fiscal year, if changed
since last report)
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months, and (2) has been subject to such filing requirements
for the past 90 days.
Yes X No
Common Stock, without par value - 147,567,114 shares outstanding on July 31,
1996.
1
BALTIMORE GAS AND ELECTRIC COMPANY
PART I. FINANCIAL INFORMATION
-----------------------------
CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
Quarter Ended June 30, Six Months Ended June 30,
---------------------- -------------------------
1996 1995 1996 1995
----------- ----------- ----------- -----------
(In Thousands, Except Per-Share Amounts)
Revenues
Electric $ 517,780 $ 504,627 $ 1,072,224 $ 1,012,451
Gas 93,515 67,968 312,779 220,753
Diversified businesses 120,412 69,905 208,034 127,102
----------- ----------- ----------- -----------
Total revenues 731,707 642,500 1,593,037 1,360,306
----------- ----------- ----------- -----------
Expenses Other Than Interest and Income Taxes
Electric fuel and purchased energy 127,468 133,128 281,320 280,582
Gas purchased for resale 49,384 29,188 178,412 110,991
Operations 130,196 134,593 262,364 266,128
Maintenance 60,811 51,362 95,252 88,243
Diversified businesses - selling, general, and administrative 84,251 52,638 151,824 93,746
Depreciation and amortization 82,332 75,337 167,730 152,015
Taxes other than income taxes 48,628 45,334 106,183 99,459
----------- ----------- ----------- -----------
Total expenses other than interest and income taxes 583,070 521,580 1,243,085 1,091,164
----------- ----------- ----------- -----------
Income From Operations 148,637 120,920 349,952 269,142
----------- ----------- ----------- -----------
Other Income
Allowance for equity funds used during construction 2,006 4,832 3,971 10,201
Equity in earnings of Safe Harbor Water Power Corporation 1,123 1,108 2,247 2,215
Net other income and deductions (1,950) (3,328) (4,098) (5,938)
----------- ----------- ----------- -----------
Total other income 1,179 2,612 2,120 6,478
----------- ----------- ----------- -----------
Income Before Interest and Income Taxes 149,816 123,532 352,072 275,620
----------- ----------- ----------- -----------
Interest Expense
Interest charges 53,054 55,333 105,772 110,310
Capitalized interest (3,416) (3,683) (6,568) (7,167)
Allowance for borrowed funds used during construction (1,083) (2,614) (2,146) (5,519)
----------- ----------- ----------- -----------
Net interest expense 48,555 49,036 97,058 97,624
----------- ----------- ----------- -----------
Income Before Income Taxes 101,261 74,496 255,014 177,996
----------- ----------- ----------- -----------
Income Taxes
Current 23,232 7,946 70,131 4,913
Deferred 15,387 17,689 23,372 55,395
Investment tax credit adjustments (1,911) (2,028) (3,823) (4,055)
----------- ----------- ----------- -----------
Total income taxes 36,708 23,607 89,680 56,253
----------- ----------- ----------- -----------
Net Income 64,553 50,889 165,334 121,743
Preferred and Preference Stock Dividends 12,104 9,952 21,768 19,904
----------- ----------- ----------- -----------
Earnings Applicable to Common Stock $ 52,449 $ 40,937 $ 143,566 $ 101,839
=========== =========== =========== ===========
Average Shares of Common Stock Outstanding 147,527 147,527 147,527 147,527
Earnings Per Share of Common Stock $ 0.36 $ 0.28 $ 0.97 $ 0.69
Dividends Declared Per Share of Common Stock $ 0.40 $ 0.39 $ 0.79 $ 0.77
See Notes to Consolidated Financial Statements.
2
PART I. FINANCIAL INFORMATION (Continued)
-----------------------------------------
CONSOLIDATED BALANCE SHEETS June 30, December 31,
1996* 1995
----------- -----------
(in Thousands)
ASSETS
Current Assets
Cash and cash equivalents ........................................................ $ 38,034 $ 23,443
Accounts receivable (net of allowance for uncollectibles ......................... 418,823 400,005
of $17,673 and $16,390 respectively)
Fuel stocks ...................................................................... 59,240 59,614
Materials and supplies ........................................................... 147,866 145,900
Prepaid taxes other than income taxes ............................................ 1,953 60,508
Deferred income taxes ............................................................ 12,810 36,831
Trading securities ............................................................... 64,175 47,990
Other ............................................................................ 29,380 31,487
----------- -----------
Total current assets ............................................................. 772,281 805,778
----------- -----------
Investments and Other Assets
Real estate projects ............................................................. 496,591 479,344
Power generation systems ......................................................... 364,447 358,629
Financial investments ............................................................ 201,490 205,841
Nuclear decommissioning trust fund ............................................... 101,871 85,811
Net pension asset ................................................................ 76,108 60,077
Safe Harbor Water Power Corporation .............................................. 34,334 34,327
Senior living facilities ......................................................... 29,086 16,045
Other ............................................................................ 75,550 71,894
----------- -----------
Total investments and other assets ............................................... 1,379,477 1,311,968
----------- -----------
Utility Plant
Plant in service
Electric ....................................................................... 6,474,765 6,360,624
Gas ............................................................................ 731,364 692,693
Common ......................................................................... 530,415 522,450
----------- -----------
Total plant in service ......................................................... 7,736,544 7,575,767
Accumulated depreciation ......................................................... (2,577,104) (2,481,801)
----------- -----------
Net plant in service ............................................................. 5,159,440 5,093,966
Construction work in progress .................................................... 205,580 247,296
Nuclear fuel (net of amortization) ............................................... 125,807 130,782
Plant held for future use ........................................................ 25,890 25,552
----------- -----------
Net utility plant ................................................................ 5,516,717 5,497,596
----------- -----------
Deferred Charges
Regulatory assets (net) .......................................................... 610,170 637,915
Other deferred charges ........................................................... 67,293 63,406
----------- -----------
Total deferred charges ........................................................... 677,463 701,321
----------- -----------
TOTAL ASSETS ....................................................................... $ 8,345,938 $ 8,316,663
=========== ===========
* Unaudited
See Notes to Consolidated Financial Statements.
3
PART I. FINANCIAL INFORMATION (Continued)
-----------------------------------------
CONSOLIDATED BALANCE SHEETS June 30, December 31,
1996* 1995
----------- -----------
(In Thousands)
LIABILITIES AND CAPITALIZATION
Current Liabilities
Short-term borrowings ............................................................ $ 274,845 $ 279,305
Current portions of long-term debt and preference stock .......................... 133,953 146,969
Accounts payable ................................................................. 147,859 177,092
Customer deposits ................................................................ 27,447 26,857
Accrued taxes .................................................................... 2,404 8,244
Accrued interest ................................................................. 56,724 56,670
Dividends declared ............................................................... 67,924 67,198
Accrued vacation costs ........................................................... 35,621 33,403
Other ............................................................................ 21,645 39,417
----------- -----------
Total current liabilities ........................................................ 768,422 835,155
----------- -----------
Deferred Credits and Other Liabilities
Deferred income taxes ............................................................ 1,307,231 1,311,530
Pension and postemployment benefits .............................................. 155,269 148,594
Decommissioning of federal uranium enrichment facilities ......................... 43,694 43,695
Other ............................................................................ 70,005 55,568
----------- -----------
Total deferred credits and other liabilities ..................................... 1,576,199 1,559,387
----------- -----------
Capitalization
Long-term Debt
First refunding mortgage bonds of BGE ............................................ 1,637,341 1,538,528
Other long-term debt of BGE ...................................................... 637,000 649,500
Long-term debt of Constellation Companies ........................................ 561,374 546,903
Unamortized discount and premium ................................................. (14,911) (15,708)
Current portion of long-term debt ................................................ (94,953) (120,969)
----------- -----------
Total long-term debt ............................................................. 2,725,851 2,598,254
----------- -----------
Preferred Stock .................................................................... -- 59,185
----------- -----------
Redeemable Preference Stock ........................................................ 266,500 268,000
Current portion of redeemable preference stock ................................... (39,000) (26,000)
----------- -----------
Total redeemable preference stock ................................................ 227,500 242,000
----------- -----------
Preference Stock Not Subject to Mandatory Redemption ............................... 210,000 210,000
----------- -----------
Common Shareholders' Equity
Common stock ..................................................................... 1,425,641 1,425,805
Retained earnings ................................................................ 1,408,437 1,381,417
Net unrealized gain on available-for-sale securities ............................. 3,888 5,460
----------- -----------
Total common shareholders' equity ................................................ 2,837,966 2,812,682
----------- -----------
Total capitalization ............................................................. 6,001,317 5,922,121
----------- -----------
TOTAL LIABILITIES AND CAPITALIZATION ............................................... $ 8,345,938 $ 8,316,663
=========== ===========
* Unaudited
See Notes to Consolidated Financial Statements.
4
PART I. FINANCIAL INFORMATION (Continued)
-----------------------------------------
CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
Six Months Ended June 30,
-------------------------
1996 1995
--------- ---------
(In Thousands)
Cash Flows From Operating Activities
Net income ............................................................................... $ 165,334 $ 121,743
Adjustments to reconcile to net cash provided by operating activities
Depreciation and amortization .......................................................... 191,549 180,168
Deferred income taxes .................................................................. 23,372 55,395
Investment tax credit adjustments ...................................................... (3,823) (4,055)
Deferred fuel costs .................................................................... 20,060 19,978
Disallowance of replacement energy costs ............................................... 6,764 --
Accrued pension and postemployment benefits ............................................ (9,999) (11,504)
Allowance for equity funds used during construction .................................... (3,971) (10,201)
Equity in earnings of affiliates and joint ventures (net) .............................. (22,944) (5,579)
Changes in current assets, other than sale of accounts receivable ...................... 26,530 23,776
Changes in current liabilities, other than short-term borrowings ....................... (49,651) (80,720)
Other .................................................................................. 18,455 711
--------- ---------
Net cash provided by operating activities ................................................ 361,676 289,712
--------- ---------
Cash Flows From Financing Activities
Proceeds from issuance of
Short-term borrowings (net) ............................................................ (4,460) 49,800
Long-term debt ......................................................................... 161,346 10,694
Common stock ........................................................................... (22) 83
Reacquisition of long-term debt .......................................................... (70,615) (20,451)
Reacquisition of preferred and preference stock .......................................... (63,559) --
Common stock dividends paid .............................................................. (115,071) (112,120)
Preferred and preference stock dividends paid ............................................ (19,785) (19,904)
Other .................................................................................... (414) (810)
--------- ---------
Net cash used in financing activities .................................................... (112,580) (92,708)
--------- ---------
Cash Flows From Investing Activities
Utility construction expenditures ........................................................ (164,747) (177,331)
Allowance for equity funds used during construction ...................................... 3,971 10,201
Nuclear fuel expenditures ................................................................ (15,125) (16,310)
Deferred energy conservation expenditures ................................................ (14,735) (18,869)
Contributions to nuclear decommissioning trust fund ...................................... (16,667) (4,890)
Purchases of marketable equity securities ................................................ (22,709) (6,759)
Sales of marketable equity securities .................................................... 24,223 32,169
Other financial investments .............................................................. 5,938 3,869
Real estate projects ..................................................................... (19,913) (4,473)
Power generation systems ................................................................. (9,798) (16,458)
Other .................................................................................... (4,943) (9,509)
--------- ---------
Net cash used in investing activities .................................................... (234,505) (208,360)
--------- ---------
Net Increase (Decrease) in Cash and Cash Equivalents ....................................... 14,591 (11,356)
Cash and Cash Equivalents at Beginning of Period ........................................... 23,443 38,590
--------- ---------
Cash and Cash Equivalents at End of Period ................................................. $ 38,034 $ 27,234
========= =========
Other Cash Flow Information
Cash paid during the period for:
Interest (net of amounts capitalized) .................................................. $ 96,790 $ 95,233
Income taxes ........................................................................... $ 74,759 $ 35,771
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
- ----------------------
The following reflects issuances and redemptions of long-term debt and
equity securities during the period from January 1, 1996 through the date of
this report:
Long-Term Debt
--------------
On June 24, 1996, BGE issued $125,000,000 principal amount of Remarketed
Floating Rate Series Due September 1, 2006 First Refunding Mortgage Bonds at a
price of 99.90%. The 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 will redeem $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 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
6
Also, on July 1, 1996, BGE exercised its option to double-up the required
sinking fund for the 8.625% Cumulative Preference Stock 1990 Series ($100 par
value) by redeeming a total of 260,000 shares at par.
Common Stock
------------
In July 1996, BGE issued a total of 40,000 shares of Common Stock, without
par value, through its Common Stock Continuous Offering Program with net
proceeds to BGE of approximately $1,142,000.
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
7
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 - 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.
Public Service Commission of Maryland (PSC) - Hearings are in progress and
testimony has been filed by all parties to the proceeding. Office of
People's Counsel (the advocates for residential customers) recommended that
the Commission 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 is recommending a rate
decrease of approximately $86 million ($60 million to BGE customers, $26
million to PEPCO customers), with Merger savings being reflected in further
reduced rates of approximately $71 million ($50 million to BGE customers,
$21 million to PEPCO customers) contemporaneous with the date of the Merger.
A number of other recommendations are also included in People's Counsel's
testimony. The Maryland Energy Administration (MEA) disagreed with the
regulatory plan for the new company. MEA has recommended that the PSC adopt
an alternative regulatory plan which includes an approximately $72 million
rate decrease for the new company and a 5-year rate freeze. MEA stated that
if the PSC found that a current rate decrease was appropriate, the $72
million was based on synergy savings and thus would be in addition to any
current rate decrease. PSC Staff testimony recommends an immediate rate
decrease (BGE's rates reduced by $68.5 million and PEPCO's by $21.2 million
at the time of the
8
Merger) and that a further 5.18 percent decrease (essentially all future
savings) be imposed on the new company one year after the Merger.
District of Columbia Public Service Commission - Recently announced its
procedural schedule, and parties in that proceeding are scheduled to file
testimony by September 12, 1996.
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.
Environmental Matters
- ---------------------
The Clean Air Act of 1990 (the Act) contains two titles designed to reduce
emissions of sulfur dioxide and nitrogen oxide (NOx) from electric generating
stations. Title IV contains provisions for compliance in two separate phases.
Phase I of Title IV became effective January 1, 1995, and Phase II of Title IV
must be implemented by 2000. BGE met the requirements of Phase I by installing
flue gas desulfurization systems and fuel switching and through unit
retirements. BGE is currently examining what actions will be required in order
to comply with Phase II of the Act. However, BGE anticipates that compliance
will be attained by some combination of fuel switching, flue gas
desulfurization, unit retirements, or allowance trading.
At this time, plans for complying with NOx control requirements under Title
I of the Act are less certain because all implementation regulations have not
yet been finalized by the government. It is expected that by the year 1999 these
regulations will require additional NOx controls for ozone attainment at BGE's
generating plants and at other BGE facilities. The controls will result in
additional expenditures that are difficult to predict prior to the issuance of
such regulations. Based on existing and proposed ozone nonattainment
regulations, BGE currently estimates that the NOx controls at BGE's generating
plants will cost approximately $90 million. BGE is currently unable to predict
the cost of compliance with the additional requirements at other BGE facilities.
BGE has been notified by the Environmental Protection Agency and several
state agencies that it is being considered a potentially responsible party with
respect to the cleanup of certain environmentally contaminated sites owned and
operated by third parties. In addition, a subsidiary of Constellation Holdings,
Inc. has been named as a defendant in a case concerning an alleged
environmentally contaminated site owned and operated by a third party. Cleanup
costs for these sites cannot be
9
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 have not been determined. BGE has recognized estimated environmental
costs at these sites which are considered probable totaling $50 million in
nominal dollars as of June 30, 1996. 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.
10
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.
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 $44.1 million.
Recoverability of Electric Fuel Costs
- -------------------------------------
By statute, actual electric fuel costs are recoverable so long as the
Public Service Commission of Maryland (PSC) finds that BGE demonstrates that,
among other things, it has maintained the productive capacity of its generating
plants at a reasonable level. The PSC and Maryland's highest appellate court
have interpreted this as permitting a subjective evaluation of each unplanned
outage at BGE's generating plants to determine whether or not BGE had
implemented all reasonable and cost-effective maintenance and operating control
procedures appropriate for preventing the outage. Effective January 1, 1987, the
PSC authorized the establishment of a Generating Unit Performance Program (GUPP)
to measure, annually, utility compliance with maintaining the productive
capacity of generating plants at reasonable levels by establishing a system-wide
generating performance target and individual performance targets for each base
load generating unit. In 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.
11
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 Order concluded there was
sufficient cause to excuse any avoidable failures to maintain productive
capacity at higher levels.
12
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 are scheduled in
this proceeding for August 1996, although an initial decision is not expected
until some time in 1997.
13
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
---------------------------------------------------------------
RESULTS OF OPERATIONS
---------------------
The financial condition and results of operations of Baltimore Gas and
Electric Company (BGE) and its subsidiaries (collectively, the Company) are set
forth in the Consolidated Financial Statements and Notes to Consolidated
Financial Statements (Notes) sections of this Report. Factors significantly
affecting results of operations, liquidity, and capital resources are discussed
below.
RESULTS OF OPERATIONS FOR THE QUARTER AND SIX MONTHS ENDED JUNE 30, 1996
COMPARED WITH THE CORRESPONDING PERIODS OF 1995
Earnings per Share of Common Stock
- ----------------------------------
Consolidated earnings per share for the quarter and six months ended June
30, 1996 were $.36 and $.97, respectively, which represent increases of $.08 and
$.28 compared to the earnings for the corresponding periods of 1995. These
increases in earnings per share reflect a higher level of earnings applicable to
common stock. The earnings per share are summarized as follows:
Quarter Ended Six Months Ended
June 30 June 30
------- -------
1996 1995 1996 1995
---- ---- ---- ----
Utility operations $.26 $.25 $.83 $.63
Diversified businesses .10 .03 .14 .06
--- --- --- ---
Total $.36 $.28 $.97 $.69
==== ==== ==== ====
Earnings Applicable to Common Stock
- -----------------------------------
Earnings applicable to common stock increased $11.5 million during the
quarter and $41.7 million during the six months ended June 30, 1996. These
increases reflect higher earnings from both utility operations and diversified
businesses.
Earnings from utility operations increased slightly during the quarter
ended June 30, 1996 as compared to the corresponding period last year primarily
due to higher electric system sales resulting from the hotter spring weather,
offset partially by a $4.5 million net-of-tax charge for the disallowance of
certain replacement power costs related to 1987 outages at both units of the
Calvert Cliffs Nuclear Power Plant. In addition to the factors noted above,
earnings from utility operations increased during the six months ended June 30,
1996 primarily due to higher electric and gas system sales resulting from the
colder winter weather in 1996 as compared to last year. The effect of weather on
utility sales is discussed on pages 15 and 16.
14
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 gas base rate increase authorized by the PSC in
November 1995 favorably affected utility earnings during the quarter and six
months ended June 30, 1996. The electric fuel rate cases now pending before the
PSC discussed on pages 11 through 13 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 its subsidiaries (collectively,
the Constellation Companies), BGE Home Products & Services, Inc. and Subsidiary
(HP&S), BGE Energy Projects & Services, Inc. (EP&S) and BNG, Inc., increased
during the quarter and six months ended June 30, 1996 compared to the
corresponding periods of 1995. Diversified businesses' earnings are discussed on
pages 21 through 24.
Effect of Weather on Utility Sales
- ----------------------------------
Weather conditions affect BGE's utility sales. BGE measures weather
conditions using degree days. A degree day is the difference between the average
daily actual temperature and the baseline temperature of 65 degrees. Colder
weather during the winter, as measured by greater heating degree days, results
in greater demand for electricity and gas to operate heating systems.
Conversely, warmer weather during the winter, measured by fewer heating degree
days, results in less demand for electricity and gas to operate heating systems.
Hotter weather during the summer, measured by more cooling degree days, results
in greater demand for electricity to operate cooling systems. Conversely, cooler
weather during the summer, measured by fewer cooling degree days, results in
less demand for electricity to operate cooling systems. The degree-days chart
below presents information regarding heating and cooling degree days for the
quarter and six months ended June 30, 1996 and 1995.
15
Quarter Ended Six Months Ended
June 30 June 30
------- -------
1996 1995 1996 1995
---- ---- ---- ----
Heating degree days............ 597 479 3,222 2,719
Percent change compared to
prior period.................. 24.6% 18.5%
Cooling degree days............ 279 252 279 252
Percent change compared to
prior period.................. 10.7% 10.7%
BGE Utility Revenues and Sales
- ------------------------------
Electric revenues changed for the quarter and six months ended June 30, 1996
because of the following factors:
Quarter Ended Six Months Ended
June 30 June 30
1996 vs. 1995 1996 vs. 1995
------------- -------------
(In millions)
System sales volumes $19.7 $49.7
Base rates 4.0 9.2
Fuel rates (2.0) (0.8)
---- ----
Revenues from system sales 21.7 58.1
Interchange and other sales (7.7) 1.7
Other revenues (0.8) 0.0
---- ---
Total $13.2 $59.8
===== =====
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 Six Months Ended
June 30 June 30
1996 vs. 1995 1996 vs. 1995
------------- -------------
Residential 10.2% 13.1%
Commercial 0.9 2.3
Industrial 1.9 3.1
Total 4.4 6.6
Sales to residential and commercial customers increased during the quarter
ended June 30, 1996 compared to last year due to periods of hotter spring
weather. Sales to residential customers also increased due to greater usage per
customer. Sales to commercial customers also increased due to a greater number
of
16
customers, offset partially by lower usage per customer. In addition to the
factors noted above, sales to residential and commercial customers increased
during the six months ended June 30, 1996 due to colder winter weather compared
to last year.
Sales to industrial customers increased during the quarter and six months
ended June 30, 1996 primarily due to an increase in the number of customers and
higher usage per customer.
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 six months
ended June 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 and six months ended June 30,
1996 as compared to the same period in 1995 as a result of a lower fuel rate,
offset partially by increased electric system sales volumes.
The fuel rate was lower for the quarter and six months ended June 30, 1996
as compared to the same period 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 1996.
Interchange and other sales represent sales of BGE's energy to the Pen
nsylvania - New Jersey - Maryland Interconnection (PJM), a regional power pool
of eight member companies including BGE, and sales to other non-PJM utilities.
These sales occur after BGE has satisfied the demand for its own system sales of
electricity, if BGE's available generation is the least costly
17
available. Interchange and other sales decreased for the quarter ended June 30,
1996 compared to last year because of lower generation from the Calvert Cliffs
Nuclear Power Plant. Interchange and other sales increased for the six months
ended June 30, 1996 because of a higher price per megawatt of electricity sold,
offset partially by lower sales volumes as compared to last year.
Gas revenues changed for the quarter and six months ended June 30, 1996
because of the following factors:
Quarter Ended Six Months Ended
June 30 June 30
1996 vs. 1995 1996 vs. 1995
------------- -------------
(In millions)
Sales volumes $(0.3) $ 9.1
Base rates 4.6 12.9
Gas cost adjustment revenues 10.9 55.6
---- ----
Revenues from system sales 15.2 77.6
Off-system Sales 9.6 13.3
Other revenues 0.7 1.1
--- ---
Total $25.5 $92.0
===== =====
Below is a comparison of the changes in gas sales volumes:
Quarter Ended Six Months Ended
June 30 June 30
1996 vs. 1995 1996 vs. 1995
------------- -------------
Residential 4.7% 17.3%
Commercial 4.8 6.8
Industrial (6.7) (6.6)
Total (0.6) 6.5
Gas sales to residential and commercial customers increased during the
quarter ended June 30, 1996 as compared to the same period last year due
primarily to cooler early spring weather and an increase in the number of
customers, offset partially by lower usage per customer. Sales to industrial
customers decreased during the quarter ended June 30, 1996 compared to last year
due primarily to decreased usage by Bethlehem Steel, offset partially by
increased usage by other industrial customers.
Gas sales to residential customers increased during the six months ended
June 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
18
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 six months ended June 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 six months ended June 30, 1996 because of higher prices for
purchased gas and 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 of 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 Six Months Ended
June 30 June 30
------- -------
1996 1995 1996 1995
---- ---- ---- ----
(In millions)
Actual costs $131.6 $124.9 $279.1 $263.5
Net (deferral) recovery of
costs under electric fuel
rate clause (see Note 1 of
the Form 10-K) (10.9) 8.2 (4.6) 17.1
Disallowed deferred fuel
costs 6.8 0.0 6.8 0.0
--- --- --- ---
Total $127.5 $133.1 $281.3 $280.6
====== ====== ====== ======
Total electric fuel and purchased energy expenses decreased during the
quarter ended June 30, 1996 as a result of the operation of the electric fuel
rate clause, offset partially by
19
increased actual costs and by the write-off of previously deferred fuel costs
($4.5 million net of taxes) which were disallowed by the PSC in a May 1996
Order. Total electric fuel and purchased energy expenses remained relatively
constant during the six months ended June 30, 1996 as a result of increased
actual costs and the write-off of previously deferred fuel costs discussed
above, offset by the operation of the electric fuel rate clause.
Actual electric fuel and purchased energy costs increased for the quarter
and six months ended June 30, 1996 as a result of a higher net output of
electricity generated and higher purchased energy costs.
Purchased gas expenses were as follows:
Quarter Ended Six Months Ended
June 30 June 30
------- -------
1996 1995 1996 1995
---- ---- ---- ----
(In millions)
Actual costs $48.3 $31.4 $175.2 $118.7
Net (deferral) recovery of costs
under purchased gas adjustment
clause (see Note 1 of the
Form 10-K) 1.1 (2.2) 3.2 (7.7)
--- ---- --- ----
Total $49.4 $29.2 $178.4 $111.0
===== ===== ====== ======
Total purchased gas expenses increased for the quarter and six months ended
June 30, 1996 compared to last year due to an increase in actual gas costs and
the operation of the purchased gas adjustment clause. The increase in actual gas
costs reflects substantially higher gas prices for the quarter and six months
ended June 30, 1996 and higher sales volumes for the six months ended June 30,
1996.
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 $5.1 million and $3.2 million,
respectively, during the quarter and six months ended June 30, 1996 compared to
the same periods last year, primarily due to higher nuclear outage maintenance
costs and labor costs.
Depreciation and amortization expense increased $7.0 million and $15.7
million, respectively, during the quarter and six months ended June 30, 1996
compared to the same periods last year
20
because of a higher level of depreciable plant in service and higher
amortization of deferred energy conservation surcharge expenditures.
Taxes other than income taxes increased $3.3 million and $6.7 million,
respectively, during the quarter and six months ended June 30, 1996 due to an
increase in property taxes resulting from plant additions during 1995 and higher
gross receipts taxes in 1996 due to increased revenues. In addition, payroll
taxes increased during 1996 due to greater incentive- based payouts and a 3%
general wage increase granted March 1, 1996.
Other Income and Expenses
- -------------------------
The Allowance for Funds Used During Construction (AFC) decreased $4.4
million and $9.6 million, respectively, for the quarter and six months ended
June 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 decreased $2.3 million and $4.5 million, respectively, for
the quarter and six months ended June 30, 1996 due primarily to the maturity of
long-term debt as well as lower interest rates as compared to last year, offset
partially by a higher overall level of debt outstanding.
Income tax expense increased $13.1 million and $33.4 million, respectively,
for the quarter and six months ended June 30, 1996 due primarily to higher
taxable income from utility operations and diversified businesses.
Diversified Businesses Earnings
- -------------------------------
Earnings per share from diversified businesses were as follows:
Quarter Ended Six Months Ended
June 30 June 30
------- -------
1996 1995 1996 1995
---- ---- ---- ----
Constellation Holdings, Inc.
Power generation systems $.07 $.01 $.11 $.03
Financial investments .04 .02 .05 .04
Real estate development and
senior living facilities (.01) .00 (.02) (.01)
Other (.01) .00 (.01) .00
---- --- ---- ---
Total Constellation Holdings, Inc. .09 .03 .13 .06
Other Subsidiaries .01 .00 .01 .00
--- --- --- ---
Total diversified businesses $.10 $.03 $.14 $.06
==== ==== ==== ====
21
The Constellation Companies' power generation systems business includes the
development, ownership, management, and operation of wholesale power generating
projects in which the Constellation Companies hold ownership interests, as well
as the provision of services to power generation projects under operation and
maintenance contracts. Power generation systems earnings increased for the
quarter and six months ended June 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,
and the $3.0 million after-tax write-off of development costs of a proposed
coal-fired power project that will not be built.
The Constellation Companies' investment in wholesale power generating
projects includes $202 million representing ownership interests in 16 projects,
including the two projects which were written-off 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 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, renegotiating
the power purchase agreements, restructuring financings, and selling its
ownership
22
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 six months ended
June 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 six months ended
June 30, 1996 are essentially unchanged from the prior year.
The Constellation Companies' real estate portfolio has experienced
continuing carrying costs and depreciation. Additionally, the Constellation
Companies have been expensing rather than capitalizing interest on certain
undeveloped land for which substantially all development activities have been
suspended. These factors have affected earnings negatively and 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.
23
To the extent the real estate market continues to improve, earnings from real
estate activities are expected to improve also.
The Constellation Companies' continued investment in real estate projects
is a function of market demand, interest rates, credit availability, and the
strength of the economy in general. The Constellation Companies' Management
believes that although the real estate market has improved, until the economy
reflects sustained growth and the excess inventory in the market in the
Baltimore-Washington corridor goes down, real estate values will not improve
significantly. If the Constellation Companies were to sell their real estate
projects in the current depressed market, losses would occur in amounts
difficult to determine. Depending upon market conditions, future sales could
also result in losses. In addition, were the Constellation Companies to change
their intent about any project from an intent to hold to an intent to sell,
applicable accounting rules would require a write-down of the project to market
value at the time of such change in intent if market value is below book value.
The earnings of other subsidiaries, which include HP&S, EP&S, and BNG,
Inc., were essentially unchanged during the quarter and six months ended June
30, 1996 compared to the same periods last year.
Environmental Matters
- ---------------------
The Company is subject to increasingly stringent federal, state, and local
laws and regulations relating to improving or maintaining the quality of the
environment. These laws and regulations require the Company to remove or remedy
the effect on the environment of the disposal or release of specified substances
at ongoing and former operating sites, including Environmental Protection Agency
Superfund sites. Details regarding these matters, including financial
information, are presented in the Environmental Matters section on pages 9 and
10 of this Report.
LIQUIDITY AND CAPITAL RESOURCES
- -------------------------------
Liquidity
- ---------
For the twelve months ended June 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 3.62 and 2.79, respectively.
Capital Requirements
- --------------------
The Company's capital requirements reflect the capital-intensive nature of
the utility business. Actual capital requirements for the six months ended June
30, 1996, along with estimated annual amounts for the years 1996 through 1998,
are reflected below.
24
Six Months Ended
June 30 Calendar Year Estimate
1996 1996 1997 1998
---- ---- ---- ----
(In millions)
Utility Business:
- -----------------
Construction expenditures
(excluding AFC)
Electric $ 97 $ 229 $211 $212
Gas 34 71 75 67
Common 27 40 49 46
-- -- -- --
Total construction expenditures 158 340 335 325
AFC 6 10 10 10
Nuclear fuel (uranium purchases
and processing charges) 15 50 45 44
Deferred energy conservation
expenditures 15 34 25 27
Retirement of long-term debt
and redemption of preferred
and preference stock 102 173 165 127
--- --- --- ---
Total utility business 296 607 580 533
--- --- --- ---
Diversified Businesses:
- -----------------------
Retirement of long-term debt 11 54 137 147
Investment requirements 35 101 71 82
-- --- -- --
Total diversified businesses 46 155 208 229
-- --- --- ---
Total $342 $ 762 $788 $762
==== ===== ==== ====
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 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 June 30, 1996, the internal generation of
cash from utility operations provided 107% 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.
Utility capital requirements not met through the internal generation of
cash are met through the issuance of debt and equity securities. The amount and
timing of issuances and redemptions depends upon market conditions and BGE's
actual capital requirements. From January 1, 1996 through the date of this
Report, BGE's issuances of long-term debt and common equity were $125 million
and $1 million, respectively. During the same
25
period, BGE redeemed, or announced the redemption of, $72 million principal
amount of debt and $87 million par value of preferred and preference stock
outstanding. All outstanding preferred stock was redeemed as described on page 6
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 in
the section titled "Diversified Businesses Capital Requirements - Debt and
Liquidity." The Constellation Companies are exploring expansion of their energy,
real estate service, and senior living facility businesses. Expansion may be
achieved in a variety of ways, including without limitation increased investment
activity and acquisitions. The Constellation Companies plan to meet their
capital requirements with a combination of debt and internal generation of cash
from their operations. Additionally, from time to time, BGE may make loans to
Constellation Holdings, Inc., or contribute equity to enhance the capital
structure of Constellation Holdings, Inc.
Historically, Constellation's energy projects have been in the United
States. Over the last year, Constellation has pursued energy projects in Latin
America. As of June 30, 1996, one of the Constellation Companies had invested
about $17.5 million and committed another $6.4 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 on pages 23 and 24 under the heading "Diversified
26
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 $10 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 on page 25 because of the type and number of projects selected for
development, the impact of market conditions on those projects, the ability to
obtain financing, and the availability of internally generated cash. The
Constellation Companies have met their investment requirements in the past
through the internal generation of cash and through borrowings from
institutional lenders.
27
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.
28
PART II. OTHER INFORMATION (Continued)
--------------------------------------
ITEM 4. Submission of Matters to a Vote of Security Holders
- ------------------------------------------------------------
On April 23, 1996, BGE held its annual meeting of shareholders. At that
meeting, the following matters were voted upon:
1. All of the Directors nominated by BGE were selected as follows:
COMMON SHARES CAST:
-------------------
For Against Abstain
--- ------- -------
H. Furlong Baldwin 117,922,276 1,666,403 1,920,304
Beverly B. Byron 118,935,404 653,274 1,920,304
J. Owen Cole 119,013,587 575,091 1,920,304
Dan A. Colussy 119,269,742 318,937 1,920,304
Edward A. Crooke 119,044,212 544,466 1,920,304
James R. Curtiss 119,082,342 506,337 1,920,304
Jerome W. Geckle 119,106,791 481,887 1,920,304
Martin L. Grass 113,244,519 6,344,160 1,920,304
Freeman A. Hrabowski 118,922,415 666,263 1,920,304
Nancy Lampton 119,249,626 339,052 1,920,304
George V. McGowan 118,931,006 657,672 1,920,304
Christian H. Poindexter 118,527,115 1,061,563 1,920,304
George L. Russell, Jr. 117,639,936 1,948,743 1,920,304
Michael D. Sullivan 118,677,449 911,229 1,920,304
2. Coopers & Lybrand, L.L.P. was reelected as independent accountants, and
with respect to holders of common stock, the number of affirmative votes
cast were 119,603,070. The number of negative votes cast were 1,195,725,
and the number of abstentions were 1,229,082.
3. The shareholder proposal requesting that the Board of Directors refrain
from providing retirement benefits to non- employee directors, unless the
benefits are submitted for shareholder approval, was defeated. With respect
to holders of common stock, the number of affirmative votes cast for the
proposal was 43,028,042, the number of negative votes cast for the proposal
was 57,056,382 and the number of abstentions was 4,767,559.
29
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. 4 Supplemental Indenture between Baltimore
Gas and Electric Company and Bankers Trust
Company, as Trustee, dated as of
June 15, 1996.
Exhibit No. 10(a) Baltimore Gas and Electric Company
Nonqualified Deferred Compensation
Plan which became effective
June 1, 1996.
Exhibit No. 10(b) Grantor Trust Agreement dated as of
June 1, 1996 between Baltimore Gas and
Electric Company and T. Rowe Price
Trust Company.
Exhibit No. 12 Computation of Ratio of Earnings to
Fixed Charges and Computation of Ratio of
Earnings to Combined Fixed Charges
and Preferred and Preference
Dividend Requirements.
Exhibit No. 27 Financial Data Schedule.
*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 August 13, 1996 /s/ C.W. Shivery
--------------- ----------------
C. W. Shivery, Vice President
on behalf of the Registrant and
as Principal Financial Officer
30
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.
4 Supplemental Indenture
between Baltimore Gas and Electric
Company and Bankers Trust Company, as
Trustee, dated as of June 15, 1996.
10(a) Baltimore Gas and Electric Company
Nonqualified Deferred Compensation Plan
which became effective June 1, 1996.
10(b) Grantor Trust Agreement dated as of
June 1, 1996 between Baltimore Gas and Electric
Company and T. Rowe Price Trust Company.
12 Computation of Ratio of
Earnings to Fixed Charges and
Computation of Ratio of Earnings to
Combined Fixed Charges and Preferred and
Preference Dividend Requirements.
27 Financial Data Schedule.
*Incorporated by Reference.
31