Exhibit No. 99
Report of Independent Accountants
- ---------------------------------
To the Shareholders of Constellation Energy Group, Inc.
In our opinion, the accompanying consolidated balance sheets and the related
consolidated statements of income, comprehensive income, cash flows, common
shareholders' equity, capitalization, and income taxes present fairly, in all
material respects, the financial position of Constellation Energy Group, Inc.
and Subsidiaries ("the Company") at December 31, 2001 and 2000, and the results
of their operations and their cash flows for each of the three years in the
period ended December 31, 2001 in conformity with accounting principles
generally accepted in the United States of America. These financial statements
are the responsibility of the Company's management; our responsibility is to
express an opinion on these financial statements based on our audits. We
conducted our audits of these statements in accordance with auditing standards
generally accepted in the United States of America, which require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements, assessing the accounting principles used and significant estimates
made by management, and evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
As discussed in Note 1 to the consolidated financial statements, the
Company changed its method of accounting for derivative and hedging activities
pursuant to Statement of Financial Accounting Standards No. 133, Accounting for
Derivative Instruments and Hedging Activities, as amended by Statement of
Financial Accounting Standards No. 138, Accounting for Certain Derivative
Instruments and Certain Hedging Activities (an amendment of FASB Statement No.
133).
/s/ PricewaterhouseCoopers LLP
- ------------------------------
PricewaterhouseCoopers LLP
Baltimore, Maryland
January 21, 2002
1
Consolidated Statements of Income
Constellation Energy Group, Inc. and Subsidiaries
Year Ended December 31, 2001 2000 1999
- -----------------------------------------------------------------------------------------------------------------------------------
(In millions, except per share amounts)
Revenues
Nonregulated revenues $1,214.4 $1,114.0 $1,105.6
Regulated electric revenues 2,039.6 2,134.7 2,258.8
Regulated gas revenues 674.3 603.8 476.5
- -----------------------------------------------------------------------------------------------------------------------------------
Total revenues 3,928.3 3,852.5 3,840.9
Expenses
Operating expenses 2,392.2 2,311.4 2,339.6
Workforce reduction costs 105.7 7.0 --
Contract termination related costs 224.8 -- --
Impairment losses and other costs 202.1 -- 64.3
Depreciation and amortization 419.1 470.0 449.8
Taxes other than income taxes 226.6 221.5 227.3
- -----------------------------------------------------------------------------------------------------------------------------------
Total expenses 3,570.5 3,009.9 3,081.0
- -----------------------------------------------------------------------------------------------------------------------------------
Income from Operations 357.8 842.6 759.9
Other Income 1.3 4.2 7.9
- -----------------------------------------------------------------------------------------------------------------------------------
Income Before Fixed Charges and Income Taxes 359.1 846.8 767.8
Fixed Charges
Interest expense 283.2 282.4 248.0
Interest capitalized and allowance for borrowed funds
used during construction (57.6) (24.2) (6.5)
BGE preference stock dividends 13.2 13.2 13.5
- -----------------------------------------------------------------------------------------------------------------------------------
Total fixed charges 238.8 271.4 255.0
- -----------------------------------------------------------------------------------------------------------------------------------
Income Before Income Taxes 120.3 575.4 512.8
Income Taxes 37.9 230.1 186.4
- -----------------------------------------------------------------------------------------------------------------------------------
Income Before Extraordinary Item and Cumulative Effect of
Change in Accounting Principle 82.4 345.3 326.4
Extraordinary Loss, Net of Income Taxes of $30.4 (see Note 5) -- -- (66.3)
Cumulative Effect of Change in Accounting Principle,
Net of Income Taxes of $5.6 (see Note 1) 8.5 -- --
- -----------------------------------------------------------------------------------------------------------------------------------
Net Income $ 90.9 $ 345.3 $ 260.1
===================================================================================================================================
Earnings Applicable to Common Stock $ 90.9 $ 345.3 $ 260.1
===================================================================================================================================
Average Shares of Common Stock Outstanding 160.7 150.0 149.6
Earnings Per Common Share and Earnings Per Common Share
--Assuming Dilution Before Extraordinary Item and
Cumulative Effect of Change in Accounting Principle $ .52 $2.30 $2.18
Extraordinary Loss -- -- (.44)
Cumulative Effect of Change in Accounting Principle .05 -- --
- -----------------------------------------------------------------------------------------------------------------------------------
Earnings Per Common Share and
Earnings Per Common Share--Assuming Dilution $ .57 $2.30 $1.74
===================================================================================================================================
See Notes to Consolidated Financial Statements.
Certain prior-year amounts have been reclassified to conform with the current
year's presentation.
2
Consolidated Statements of Comprehensive Income
Constellation Energy Group, Inc. and Subsidiaries
Year Ended December 31, 2001 2000 1999
- -----------------------------------------------------------------------------------------------------------------------------------
(In millions)
Net Income $ 90.9 $ 345.3 $ 260.1
Other comprehensive income, net of taxes
Financial securities 124.5 18.6 3.9
Hedging instruments 102.6 -- --
Minimum pension liability (44.7) -- --
- -----------------------------------------------------------------------------------------------------------------------------------
Comprehensive Income Before Cumulative Effect of
Change in Accounting Principle 273.3 363.9 264.0
Cumulative Effect of Change in Accounting Principle,
Net of Income Taxes of $22.6 (35.5) -- --
- -----------------------------------------------------------------------------------------------------------------------------------
Comprehensive Income $ 237.8 $ 363.9 $ 264.0
===================================================================================================================================
See Notes to Consolidated Financial Statements.
Certain prior-year amounts have been reclassified to conform with the current
year's presentation.
3
Consolidated Balance Sheets
Constellation Energy Group, Inc. and Subsidiaries
At December 31, 2001 2000
- -----------------------------------------------------------------------------------------------------------------------------------
(In millions)
Assets
Current Assets
Cash and cash equivalents $ 72.4 $ 182.7
Accounts receivable (net of allowance for uncollectibles
of $22.8 and $21.3, respectively) 738.9 792.6
Trading securities 178.2 189.3
Mark-to-market energy assets 398.4 453.1
Fuel stocks 108.0 78.2
Materials and supplies 196.3 151.3
Prepaid taxes other than income taxes 93.4 73.5
Other 74.6 52.8
- -----------------------------------------------------------------------------------------------------------------------------------
Total current assets 1,860.2 1,973.5
- -----------------------------------------------------------------------------------------------------------------------------------
Investments and Other Assets
Real estate projects and investments 210.7 290.3
Investments in power projects 499.1 510.6
Investment in Orion Power Holdings, Inc. 442.5 192.0
Financial investments 60.7 161.0
Nuclear decommissioning trust funds 683.5 228.7
Net pension asset -- 93.2
Mark-to-market energy assets 1,819.8 2,069.3
Other 207.4 123.0
- -----------------------------------------------------------------------------------------------------------------------------------
Total investments and other assets 3,923.7 3,668.1
- -----------------------------------------------------------------------------------------------------------------------------------
Property, Plant and Equipment
Regulated property, plant and equipment
Plant in service 4,862.4 4,780.3
Construction work in progress 81.8 75.3
Plant held for future use 4.5 4.5
- -----------------------------------------------------------------------------------------------------------------------------------
Total regulated property, plant and equipment 4,948.7 4,860.1
Nonregulated generation property, plant and equipment 6,551.1 5,286.8
Other nonregulated property, plant and equipment 192.9 147.0
Nuclear fuel (net of amortization) 169.5 128.3
Accumulated depreciation (4,161.8) (3,756.7)
- -----------------------------------------------------------------------------------------------------------------------------------
Net property, plant and equipment 7,700.4 6,665.5
- -----------------------------------------------------------------------------------------------------------------------------------
Deferred Charges
Regulatory assets (net) 463.8 514.9
Other 129.5 117.3
- -----------------------------------------------------------------------------------------------------------------------------------
Total deferred charges 593.3 632.2
- -----------------------------------------------------------------------------------------------------------------------------------
Total Assets $14,077.6 $12,939.3
===================================================================================================================================
See Notes to Consolidated Financial Statements.
Certain prior-year amounts have been reclassified to conform with the current
year's presentation.
4
Consolidated Balance Sheets
Constellation Energy Group, Inc. and Subsidiaries
At December 31, 2001 2000
- -----------------------------------------------------------------------------------------------------------------------------------
(In millions)
Liabilities and Capitalization
Current Liabilities
Short-term borrowings $ 975.0 $ 243.6
Current portion of long-term debt 1,406.7 906.6
Accounts payable 534.4 750.0
Mark-to-market energy liabilities 323.3 358.2
Dividends declared 23.0 66.5
Other 297.1 250.8
- -----------------------------------------------------------------------------------------------------------------------------------
Total current liabilities 3,559.5 2,575.7
- -----------------------------------------------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities
Deferred income taxes 1,431.0 1,353.2
Mark-to-market energy liabilities 1,476.5 1,636.3
Net pension liability 173.3 --
Postretirement and postemployment benefits 330.9 265.2
Deferred investment tax credits 93.4 101.4
Other 266.9 484.2
- -----------------------------------------------------------------------------------------------------------------------------------
Total deferred credits and other liabilities 3,772.0 3,840.3
- -----------------------------------------------------------------------------------------------------------------------------------
Capitalization
Long-term debt 2,712.5 3,159.3
BGE preference stock not subject to mandatory redemption 190.0 190.0
Common shareholders' equity 3,843.6 3,174.0
- -----------------------------------------------------------------------------------------------------------------------------------
Total capitalization 6,746.1 6,523.3
- -----------------------------------------------------------------------------------------------------------------------------------
Commitments, Guarantees, and Contingencies (see Note 11)
Total Liabilities and Capitalization $14,077.6 $12,939.3
===================================================================================================================================
See Notes to Consolidated Financial Statements.
Certain prior-year amounts have been reclassified to conform with the current
year's presentation.
5
Consolidated Statements of Cash Flows
Constellation Energy Group, Inc. and Subsidiaries
Year Ended December 31, 2001 2000 1999
- -----------------------------------------------------------------------------------------------------------------------------------
(In millions)
Cash Flows From Operating Activities
Net income $ 90.9 $ 345.3 $260.1
Adjustments to reconcile to net cash provided by operating activities
Cumulative effect of change in accounting principle (8.5) -- --
Extraordinary loss -- -- 66.3
Depreciation and amortization 468.9 524.8 505.9
Deferred income taxes (26.5) 42.1 13.0
Investment tax credit adjustments (8.1) (8.4) (8.6)
Deferred fuel costs 37.6 2.8 (61.1)
Accrued pension and postemployment benefits 55.3 27.9 36.1
Gain on sale of investments (40.7) (64.1) --
Loss (gain) on sale of subsidiaries and plant assets 43.3 (13.3) --
Deregulation transition cost -- 24.0 --
Workforce reduction costs 105.7 7.0 --
Contract termination related costs 26.2 -- --
Impairment losses and other costs 158.7 -- 64.3
Equity in earnings of affiliates and joint ventures (net) 2.0 (5.3) (7.6)
Changes in mark-to-market energy assets and liabilities 109.5 (379.6) (114.3)
Changes in other current assets (57.7) (230.7) (216.4)
Changes in other current liabilities (218.8) 406.2 121.0
Other (164.5) 172.2 20.3
- -----------------------------------------------------------------------------------------------------------------------------------
Net cash provided by operating activities 573.3 850.9 679.0
- -----------------------------------------------------------------------------------------------------------------------------------
Cash Flows From Investing Activities
Purchases of property, plant and equipment and
other capital expenditures (1,318.3) (1,079.0) (616.5)
Acquisition of Nine Mile Point (382.7) -- --
Sale of (investment in) Orion 26.2 (101.5) (97.7)
Contributions to nuclear decommissioning trust funds (22.0) (13.2) (17.6)
Purchases of marketable equity securities (33.2) (80.8) (27.3)
Sales of marketable equity securities 132.6 110.2 34.9
Proceeds from the sale of property, plant, and equipment 112.0 20.8 --
Other investments 12.7 37.0 109.1
- -----------------------------------------------------------------------------------------------------------------------------------
Net cash used in investing activities (1,472.7) (1,106.5) (615.1)
- -----------------------------------------------------------------------------------------------------------------------------------
Cash Flows From Financing Activities
Net issuance (maturity) of short-term borrowings 731.4 (127.9) 371.5
Proceeds from issuance of
Long-term debt 1,175.2 1,374.0 302.8
Common stock 504.4 35.9 9.6
Repayment of long-term debt (1,510.2) (697.0) (584.4)
Redemption of preference stock -- -- (7.0)
Common stock dividends paid (120.7) (250.7) (251.1)
Other 9.0 11.3 13.7
- -----------------------------------------------------------------------------------------------------------------------------------
Net cash provided by (used in) financing activities 789.1 345.6 (144.9)
- -----------------------------------------------------------------------------------------------------------------------------------
Net (Decrease) Increase in Cash and Cash Equivalents (110.3) 90.0 (81.0)
Cash and Cash Equivalents at Beginning of Year 182.7 92.7 173.7
- -----------------------------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of Year $ 72.4 $ 182.7 $ 92.7
===================================================================================================================================
Other Cash Flow Information:
- ----------------------------
Cash paid during the year for:
Interest (net of amounts capitalized) $238.3 $268.2 $245.3
Income taxes $101.5 $184.7 $165.6
Non-Cash Transaction:
- ---------------------
In connection with our purchase of Nine Mile Point, the fair value of the net
assets purchased was $770.8 million. We paid $382.7 million in cash, including
settlement costs, and incurred a sellers' note of $388.1 million as discussed
further in Note 14 on page 40.
See Notes to Consolidated Financial Statements.
Certain prior-year amounts have been reclassified to conform with the current
year's presentation.
6
Consolidated Statements of Common Shareholders' Equity
Constellation Energy Group, Inc. and Subsidiaries
Accumulated
Other
Common Stock Retained Comprehensive Total
Years Ended December 31, 2001, 2000, and 1999 Shares Amount Earnings Income Amount
- -----------------------------------------------------------------------------------------------------------------------------------
(Dollar amounts in millions, number of shares in thousands)
Balance at December 31, 1998 149,246 $1,485.1 $1,490.3 $ 20.5 $2,995.9
Net income 260.1 260.1
Common stock dividend declared ($1.68 per share) (251.3) (251.3)
Common stock issued 310 9.6 9.6
Other (0.7) (0.7)
Net unrealized gain on securities, net of taxes of $3.2 3.9 3.9
- -----------------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 1999 149,556 1,494.0 1,499.1 24.4 3,017.5
Net income 345.3 345.3
Common stock dividend declared ($1.68 per share) (251.8) (251.8)
Common stock issued 976 35.9 35.9
Other 8.8 (0.3) 8.5
Net unrealized gain on securities, net of taxes of $9.5 18.6 18.6
- -----------------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 2000 150,532 1,538.7 1,592.3 43.0 3,174.0
Net income 90.9 90.9
Common stock dividend declared ($.48 per share) (77.1) (77.1)
Common stock issued 13,176 504.4 504.4
Other (0.9) 5.4 4.5
Cumulative effect of change in accounting principle,
net of taxes of $22.6 (35.5) (35.5)
Net unrealized gain on securities, net of taxes of $71.8 124.5 124.5
Net unrealized gain on hedging instruments,
net of taxes of $65.6 102.6 102.6
Minimum pension liability, net of taxes of $29.3 (44.7) (44.7)
- -----------------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 2001 163,708 $2,042.2 $1,611.5 $189.9 $3,843.6
===================================================================================================================================
See Notes to Consolidated Financial Statements.
Certain prior-year amounts have been reclassified to conform with the current
year's presentation.
7
Consolidated Statements of Capitalization
Constellation Energy Group, Inc. and Subsidiaries
At December 31, 2001 2000
- -----------------------------------------------------------------------------------------------------------------------------------
Long-Term Debt (In millions)
Long-term debt of Constellation Energy
7 7/8% Notes, due April 1, 2005 $ 300.0 $ 300.0
Floating rate notes, due April 4, 2003 -- 200.0
Extendible notes, due June 21, 2010 -- 300.0
Floating rate reset notes, due March 15, 2002 -- 200.0
Floating rate notes, due January 17, 2002 635.0 --
- -----------------------------------------------------------------------------------------------------------------------------------
Total long-term debt of Constellation Energy 935.0 1,000.0
- -----------------------------------------------------------------------------------------------------------------------------------
Long-term debt of nonregulated businesses
Tax-exempt debt transferred from BGE effective July 1, 2000
Pollution control loan, due July 1, 2011 36.0 36.0
Port facilities loan, due June 1, 2013 48.0 48.0
Adjustable rate pollution control loan, due July 1, 2014 20.0 20.0
5.55% Pollution control revenue refunding loan, due July 15, 2014 47.0 47.0
Economic development loan, due December 1, 2018 35.0 35.0
6.00% Pollution control revenue refunding loan, due April 1, 2024 75.0 75.0
Floating rate pollution control loan, due June 1, 2027 8.8 8.8
5 1/2% Installment series, due July 15, 2002 6.7 7.6
District Cooling facilities loan, due December 1, 2031 25.0 --
Loans under revolving credit agreements 46.0 34.0
11% Installment note, due November 7, 2006 388.1 --
Mortgage and construction loans
Floating rate mortgage notes and construction loans, due through 2005 13.8 51.3
Other mortgage notes ranging from 4.25% to 9.65% due March 15, 2009 to November 1, 2033 19.7 20.3
Unsecured notes -- 287.0
- -----------------------------------------------------------------------------------------------------------------------------------
Total long-term debt of nonregulated businesses 769.1 670.0
- -----------------------------------------------------------------------------------------------------------------------------------
First Refunding Mortgage Bonds of BGE
8 3/8% Series, due August 15, 2001 -- 122.2
7 1/4% Series, due July 1, 2002 124.0 124.0
6 1/2% Series, due February 15, 2003 124.8 124.8
6 1/8% Series, due July 1, 2003 124.9 124.9
5 1/2% Series, due April 15, 2004 125.0 125.0
Remarketed floating rate series, due September 1, 2006 111.5 111.5
7 1/2% Series, due January 15, 2007 123.5 123.5
6 5/8% Series, due March 15, 2008 124.9 124.9
7 1/2% Series, due March 1, 2023 98.1 109.9
7 1/2% Series, due April 15, 2023 84.0 84.0
- -----------------------------------------------------------------------------------------------------------------------------------
Total First Refunding Mortgage Bonds of BGE 1,040.7 1,174.7
- -----------------------------------------------------------------------------------------------------------------------------------
Other long-term debt of BGE
5.25% Notes, due December 15, 2006 300.0 --
Floating rate reset notes, due February 5, 2002 200.0 --
Floating rate reset notes, due October 19, 2001 -- 200.0
Medium-term notes, Series B 23.1 23.1
Medium-term notes, Series C 25.5 25.5
Medium-term notes, Series D 68.0 128.0
Medium-term notes, Series E 200.0 200.0
Medium-term notes, Series G 140.0 200.0
Medium-term notes, Series H -- 27.0
6.75% Remarketable or redeemable securities, due December 15, 2012 173.0 173.0
- -----------------------------------------------------------------------------------------------------------------------------------
Total other long-term debt of BGE 1,129.6 976.6
- -----------------------------------------------------------------------------------------------------------------------------------
BGE obligated mandatorily redeemable trust preferred securities of subsidiary trust holding
solely 7.16% deferrable interest subordinated debentures due June 30, 2038 250.0 250.0
Unamortized discount and premium (5.2) (5.4)
Current portion of long-term debt (1,406.7) (906.6)
- -----------------------------------------------------------------------------------------------------------------------------------
Total long-term debt $2,712.5 $3,159.3
- -----------------------------------------------------------------------------------------------------------------------------------
continued on next page
See Notes to Consolidated Financial Statements.
8
Consolidated Statements of Capitalization
Constellation Energy Group, Inc. and Subsidiaries
At December 31, 2001 2000
- -----------------------------------------------------------------------------------------------------------------------------------
(In millions)
BGE Preference Stock
Cumulative preference stock not subject to mandatory redemption, 6,500,000 shares authorized
7.125%, 1993 Series, 400,000 shares outstanding, not callable prior to July 1, 2003 $40.0 $40.0
6.97%, 1993 Series, 500,000 shares outstanding, not callable prior to October 1, 2003 50.0 50.0
6.70%, 1993 Series, 400,000 shares outstanding, not callable prior to January 1, 2004 40.0 40.0
6.99%, 1995 Series, 600,000 shares outstanding, not callable prior to October 1, 2005 60.0 60.0
- -----------------------------------------------------------------------------------------------------------------------------------
Total preference stock not subject to mandatory redemption 190.0 190.0
- -----------------------------------------------------------------------------------------------------------------------------------
Common Shareholders' Equity
Common stock without par value, 250,000,000 shares authorized; 163,707,950
and 150,531,716 shares issued and outstanding at December 31, 2001 and
2000, respectively. (At December 31, 2001, 11,797,976 shares were reserved for the
Shareholder Investment Plan and 6,000,000 were reserved for the long-term incentive plans.) 2,042.2 1,538.7
Retained earnings 1,611.5 1,592.3
Accumulated other comprehensive income 189.9 43.0
- -----------------------------------------------------------------------------------------------------------------------------------
Total common shareholders' equity 3,843.6 3,174.0
- -----------------------------------------------------------------------------------------------------------------------------------
Total Capitalization $6,746.1 $6,523.3
===================================================================================================================================
See Notes to Consolidated Financial Statements.
9
Consolidated Statements of Income Taxes
Constellation Energy Group, Inc. and Subsidiaries
Year Ended December 31, 2001 2000 1999
- --------------------------------------------------------------------------------------------------------------------------------
(Dollar amounts in millions)
Income Taxes
Current
Federal $45.5 $148.2 $176.3
State 27.0 48.2 5.7
- --------------------------------------------------------------------------------------------------------------------------------
Current taxes charged to expense 72.5 196.4 182.0
Deferred
Federal (22.4) 53.9 5.8
State (4.1) (11.8) 7.2
- --------------------------------------------------------------------------------------------------------------------------------
Deferred taxes charged to expense (26.5) 42.1 13.0
Investment tax credit adjustments (8.1) (8.4) (8.6)
- --------------------------------------------------------------------------------------------------------------------------------
Income taxes per Consolidated Statements of Income $37.9 $230.1 $186.4
================================================================================================================================
Reconciliation of Income Taxes Computed at Statutory
Federal Rate to Total Income Taxes
Income before income taxes (excluding BGE preference stock dividends) $133.5 $588.6 $526.3
Statutory federal income tax rate 35% 35% 35%
- --------------------------------------------------------------------------------------------------------------------------------
Income taxes computed at statutory federal rate 46.7 206.0 184.2
Increases (decreases) in income taxes due to
Depreciation differences not normalized on regulated activities 5.6 12.6 15.3
Allowance for equity funds used during construction (1.1) (0.9) (2.2)
Amortization of deferred investment tax credits (8.1) (8.4) (8.6)
Tax credits flowed through to income (13.4) (6.5) (3.2)
Amortization of deferred tax rate differential on regulated activities (2.1) (2.9) (3.0)
State income taxes, net of federal income tax benefit 13.5 31.7 8.2
Other (3.2) (1.5) (4.3)
- --------------------------------------------------------------------------------------------------------------------------------
Total income taxes $ 37.9 $230.1 $186.4
================================================================================================================================
Effective income tax rate 28.4% 39.1% 35.4%
At December 31, 2001 2000
- --------------------------------------------------------------------------------------------------------------------------------
(Dollar amounts in millions)
Deferred Income Taxes
Deferred tax liabilities
Net property, plant and equipment $1,156.0 $1,135.5
Income taxes recoverable through future rates 31.4 32.8
Deferred termination and postemployment costs 7.0 13.6
Deferred fuel costs 11.7 24.9
Power marketing and risk management activities 776.4 819.4
Deferred electric generation-related regulatory assets 87.1 93.7
Financial investments and hedging instruments 153.9 42.6
Other 140.9 135.6
- --------------------------------------------------------------------------------------------------------------------------------
Total deferred tax liabilities 2,364.4 2,298.1
Deferred tax assets
Accrued pension and postemployment benefit costs 132.7 76.5
Deferred investment tax credits 35.1 35.5
Nuclear decommissioning liability 32.1 28.2
Power marketing and risk management activities 549.1 638.2
Reduction of investments 82.3 29.8
Other 102.1 136.7
- --------------------------------------------------------------------------------------------------------------------------------
Total deferred tax assets 933.4 944.9
- --------------------------------------------------------------------------------------------------------------------------------
Deferred tax liability, net $1,431.0 $1,353.2
================================================================================================================================
See Notes to Consolidated Financial Statements.
Certain prior-year amounts have been reclassified to conform with the current
year's presentation.
10
Notes to Consolidated Financial Statements
- ------------------------------------------
Note 1. Significant Accounting Policies
- --------------------------------------------------------------------------------
Nature of Our Business
- ----------------------
Constellation Energy Group, Inc. (Constellation Energy) is a North American
energy company that conducts its business through various subsidiaries including
a merchant energy business and Baltimore Gas and Electric Company (BGE). Our
merchant energy business generates and markets wholesale electricity in North
America. BGE is an electric and gas public transmission and distribution utility
company with a service territory that covers the City of Baltimore and all or
part of ten counties in central Maryland. We describe our operating segments in
Note 3 on page 20.
References in this report to "we" and "our" are to Constellation Energy and
its subsidiaries, collectively. Reference in this report to the "utility
business" is to BGE.
Consolidation Policy
- --------------------
We use three different accounting methods to report our investments in our
subsidiaries or other companies: consolidation, the equity method, and the cost
method.
Consolidation
- -------------
We use consolidation when we own a majority of the voting stock of the
subsidiary. This means the accounts of our subsidiaries are combined with our
accounts. We eliminate intercompany balances and transactions when we
consolidate these accounts.
The Equity Method
- -----------------
We usually use the equity method to report investments, corporate joint
ventures, partnerships, and affiliated companies (including power projects)
where we hold a 20% to 50% voting interest. Under the equity method, we report:
o our interest in the entity as an investment in our Consolidated
Balance Sheets, and
o our percentage share of the earnings from the entity in our Consolidated
Statements of Income.
The only time we do not use this method is if we can exercise control over
the operations and policies of the company. If we have control, accounting rules
require us to use consolidation.
The Cost Method
- ---------------
We usually use the cost method if we hold less than a 20% voting interest in an
investment. Under the cost method, we report our investment at cost in our
Consolidated Balance Sheets. The only time we do not use this method is when we
can exercise significant influence over the operations and policies of the
company. If we have significant influence, accounting rules require us to use
the equity method.
Regulation of Utility Business
- ------------------------------
The Maryland Public Service Commission (Maryland PSC) provides the final
determination of the rates we charge our customers for our regulated businesses.
Generally, we use the same accounting policies and practices used by
nonregulated companies for financial reporting under accounting principles
generally accepted in the United States of America. However, sometimes the
Maryland PSC orders an accounting treatment different from that used by
nonregulated companies to determine the rates we charge our customers. When this
happens, we must defer (include as an asset or liability in our Consolidated
Balance Sheets and exclude from our Consolidated Statements of Income) certain
utility expenses and income as regulatory assets and liabilities. We have
recorded these regulatory assets and liabilities in our Consolidated Balance
Sheets in accordance with Statement of Financial Accounting Standards (SFAS) No.
71, Accounting for the Effects of Certain Types of Regulation. We summarize and
discuss our regulatory assets and liabilities further in Note 6 on page 25.
In 1997, the Financial Accounting Standards Board (FASB) through its
Emerging Issues Task Force (EITF) issued EITF 97-4, Deregulation of the Pricing
of Electricity--Issues Related to the Application of FASB Statements No. 71 and
101. The EITF concluded that a company should cease to apply SFAS No. 71 when
either legislation is passed or a regulatory body issues an order that contains
sufficient detail to determine how the transition plan will affect the
deregulated portion of the business. Additionally, a company would continue to
recognize regulatory assets and liabilities in the Consolidated Balance Sheets
to the extent that the transition plan provides for their recovery.
On November 10, 1999, the Maryland PSC issued a Restructuring Order that we
believe provided sufficient details of the transition plan to competition for
BGE's electric generation business to require BGE to discontinue the application
of SFAS No. 71 for that portion of its business. Accordingly, in the fourth
quarter of 1999, we adopted the provisions of SFAS No. 101, Regulated
Enterprises--Accounting for the Discontinuation of FASB Statement No. 71 and
EITF 97-4 for BGE's electric generation business. BGE's transmission and
distribution business continues to meet the requirements of SFAS No. 71, as that
business remains regulated. We discuss this further in Note 5 on page 23.
11
Revenues
- --------
Nonregulated Businesses
- -----------------------
Our subsidiary, Constellation Power Source, uses the mark-to-market method of
accounting, as discussed below, to account for power marketing activities. We
record all other nonregulated revenues in the period earned for services
rendered, commodities or products delivered, or contracts settled. Equity in
earnings from our investments in power projects is included in revenues.
Power marketing activities include new origination transactions and risk
management activities using contracts for energy, other energy-related
commodities, and related derivative contracts. We account for these activities
using the mark-to-market method of accounting as required by EITF 98-10,
Accounting for Contracts Involved in Energy Trading and Risk Management
Activities. Under the mark-to-market method of accounting, we record the fair
value of commodity and derivative contracts as mark-to-market energy assets and
liabilities at the time of contract execution. We record reserves to reflect
uncertainties associated with certain estimates inherent in the determination of
fair value. Mark-to-market energy revenues include:
o the fair value of new transactions at origination,
o unrealized gains and losses from changes in the fair value of open
positions,
o net gains and losses from realized transactions, and
o changes in reserves.
We record the changes in mark-to-market energy assets and liabilities on a
net basis in "Nonregulated revenues" in our Consolidated Statements of Income.
Mark-to-market energy assets and liabilities are comprised of a combination of
energy and energy-related derivative and non-derivative contracts. While some of
these contracts represent commodities or instruments for which prices are
available from external sources, other commodities and certain contracts are not
actively traded and are valued using modeling techniques to determine expected
future market prices, contract quantities, or both. The market prices used to
determine fair value reflect management's best estimate considering various
factors, including closing exchange and over-the-counter quotations, time value,
and volatility factors. However, it is possible that future market prices could
vary from those used in recording mark-to-market energy assets and liabilities,
and such variations could be material.
Certain power marketing and risk management transactions entered into under
master agreements and other arrangements provide our merchant energy business
with a right of setoff in the event of bankruptcy or default by the
counterparty. We report such transactions net in the balance sheets in
accordance with FASB Interpretation No. 39, Offsetting of Amounts Related to
Certain Contracts.
Regulated Utility
- -----------------
We record utility revenues when we provide service to customers.
Fuel and Purchased Energy Costs
- -------------------------------
We incur costs for:
o the fuel we use to generate electricity,
o purchases of electricity from others, and
o natural gas that we resell.
These costs are included in "Operating expenses" in our Consolidated
Statements of Income. We discuss each of these separately below.
Fuel Used to Generate Electricity and Purchases of Electricity From Others
- --------------------------------------------------------------------------
Effective July 1, 2000, these costs are recorded as incurred. Historically and
until July 1, 2000, we were allowed to recover our costs of electric fuel under
the electric fuel rate clause set by the Maryland PSC. Under the electric fuel
rate clause, we charged our electric customers for:
o the fuel we use to generate electricity (nuclear fuel, coal, gas, or
oil), and
o the net cost of purchases and sales of electricity.
We charged the actual costs of these items to customers with no profit to
us. To do this, we had to keep track of what we spent and what we collected from
customers under the fuel rate in a given period. Usually these two amounts were
not the same because there was a difference between the time we spent the money
and the time we collected it from our customers.
Under the electric fuel rate clause, we deferred the difference between our
actual costs of fuel and energy and what we collected from customers under the
fuel rate in a given period. We either billed or refunded our customers that
difference in the future. As a result of the Restructuring Order, the fuel rate
was discontinued effective July 1, 2000. We discuss this further in Note 6 on
page 25.
Natural Gas
- -----------
We charge our gas customers for the natural gas they purchase from us using "gas
cost adjustment clauses" set by the Maryland PSC. These clauses operate
similarly to the electric fuel rate clause described earlier in this note.
However, the Maryland PSC approved a modification of the gas cost adjustment
clauses to provide a market-based rates incentive mechanism. Under market-based
rates, our actual cost of gas is compared to a market index (a measure of the
market price of gas in a given period). The difference between our actual cost
and the market index is shared equally between shareholders and customers.
Effective November 2001, the Maryland PSC approved an order that modifies
certain provisions of the market-based rates incentive mechanism. These
provisions require that BGE secure fixed-price contracts for at least 10%, but
not more than 20%, of forecasted system supply requirements for the November
through March period. These fixed price contracts are not subject to sharing
under the market-based rates incentive mechanism.
12
Risk Management
- ---------------
We are exposed to market risk, including changes in interest rates and the
impact of market fluctuations in the price and transportation costs of
electricity, natural gas, and other commodities as discussed further in Note 12
on page 37. We use interest rate swaps to manage our interest rate exposures
associated with new debt issuances. These swaps are designated as cash-flow
hedges under SFAS No. 133, Accounting for Derivative Instruments and Hedging
Activities, as discussed later in this note, with gains or losses recorded in
"Other current assets" in our Consolidated Balance Sheets and "Accumulated other
comprehensive income," in our Consolidated Statements of Common Shareholders'
Equity and Consolidated Statements of Capitalization, in anticipation of planned
financing transactions. Any gain or loss on the hedges will be reclassified from
"Accumulated other comprehensive income" into "Interest expense" and be included
in earnings during the periods in which the interest payments being hedged
occur.
Our merchant energy and regulated gas businesses use derivative and
non-derivative instruments to manage changes in their respective commodity
prices as discussed in more detail below.
Merchant Energy Business
- ------------------------
The power marketing operation manages market risk on a portfolio basis, subject
to established risk management policies. The power marketing operation uses a
variety of derivative and non-derivative instruments, including:
o forward contracts, which commit us to purchase or sell energy commodities
in the future;
o futures contracts, which are exchange-traded standardized commitments
to purchase or sell a commodity or financial instrument, or to make a
cash settlement, at a specific price and future date;
o swap agreements, which require payments to or from counterparties based
upon the differential between two prices for a predetermined contractual
(notional) quantity; and
o option contracts, which convey the right to buy or sell a commodity,
financial instrument, or index at a predetermined price.
As part of its overall portfolio, the power marketing operation manages the
commodity price risk of our electric generation facilities, including power
sales, fuel purchases, emission credits, weather risk, and the market risk of
outages. In order to manage this risk, we may enter into fixed-price derivative
or non-derivative contracts to hedge the variability in future cash flows from
forecasted sales of electricity and purchases of fuel. The objectives for
entering into such hedges include:
o fixing the price for a portion of anticipated future electricity sales
at a level that provides an acceptable return on our electric generation
operations, and
o fixing the price of a portion of anticipated fuel purchases for the
operation of our power plants.
The portion of forecasted transactions hedged may vary based upon
management's assessment of market, weather, operational, and other factors.
Under the provisions of SFAS No. 133, we record gains and losses on
derivative contracts designated as cash-flow hedges of firm commitments or
anticipated transactions in "Accumulated other comprehensive income" in our
Consolidated Statements of Common Shareholders' Equity and Consolidated
Statements of Capitalization prior to the settlement of the anticipated hedged
physical transaction. We reclassify these gains or losses into earnings upon
settlement of the underlying hedged transaction. We record derivatives used for
hedging activities from our merchant energy business in "Other assets," and in
"Other deferred credits and other liabilities," on the Consolidated Balance
Sheets.
Regulated Electric Business
- ---------------------------
Under the Restructuring Order, effective July 1, 2000, BGE's residential rates
are frozen for a six-year period, and its commercial and industrial rates are
frozen for four to six years. BGE entered into standard offer service
arrangements with Constellation Power Source and Allegheny Energy Supply Company
to provide the energy and capacity required to meet its standard offer service
obligations through June 30, 2006.
Regulated Gas Business
- ----------------------
We use basis swaps in the winter months (November through March) to hedge our
price risk associated with natural gas purchases under our market-based rates
incentive mechanism. We also use fixed-to-floating and floating-to-fixed swaps
to hedge our price risk associated with our off-system gas sales.
The fixed portion represents a specific dollar amount that we will pay or
receive, and the floating portion represents a fluctuating amount based on a
published index that we will receive or pay. Our regulated gas business internal
guidelines do not permit the use of swap agreements for any purpose other than
to hedge price risk.
BGE's off-system gas sales activities represent trading activities under
EITF 98-10. Accordingly, we use mark-to-market accounting to record these
transactions. The trading activities relating to our off-system gas sales were
not material at December 31, 2001 and 2000.
We defer, as unrealized gains or losses, the changes in fair value of the
swap agreements under the market-based rates incentive mechanism and the
customers' portion of off-system gas sales in our Consolidated Balance Sheets.
When amounts are paid under the agreements, we report the payments as gas costs
in our Consolidated Statements of Income. We report the changes in fair value
for the shareholders' portion of off-system gas sales in earnings as a component
of gas costs.
13
Credit Risk
- -----------
Credit risk is the loss that may result from counterparty non-performance. We
are exposed to credit risk, primarily through Constellation Power Source.
Constellation Power Source uses credit policies to manage its credit risk,
including utilizing an established credit approval process, monitoring
counterparty limits, employing credit mitigation measures such as margin,
collateral or prepayment arrangements, and using master netting agreements.
Constellation Power Source measures credit risk as the replacement cost for open
energy commodity and derivative positions plus amounts owed from counterparties
for settled transactions. The replacement cost of open positions represents
unrealized gains, net of any unrealized losses, where we have a legally
enforceable right of setoff.
Due to the possibility of extreme volatility in the prices of energy
commodities and derivatives, the market value of contractual positions with
individual counterparties could exceed established credit limits or collateral
provided by those counterparties. If such a counterparty were then to fail to
perform its obligations under its contract (for example, fail to deliver the
electricity the power marketing operation had contracted for), we could sustain
a loss that could have a material impact on our financial results.
Electric and gas utilities, cooperatives, and energy marketers comprise the
majority of counterparties underlying our assets from power marketing and risk
management activities. We held cash collateral from counterparties totaling $3.5
million as of December 31, 2001 and $103.3 million as of December 31, 2000.
These amounts are included in "Other deferred credits and other liabilities" in
our Consolidated Balance Sheets.
Taxes
- -----
We summarize our income taxes in our Consolidated Statements of Income Taxes on
page 10. As you read this section, it may be helpful to refer to those
statements.
Income Tax Expense
- ------------------
We have two categories of income taxes in our Consolidated Statements of
Income--current and deferred. We describe each of these below:
o current income tax expense consists solely of regular tax less applicable
tax credits, and
o deferred income tax expense is equal to the changes in the net deferred
income tax liability, excluding amounts charged or credited to
accumulated other comprehensive income. Our deferred income tax expense
is increased or reduced for changes to the "Income taxes recoverable
through future rates (net)" regulatory asset (described later in this
note) during the year.
Investment Tax Credits
- ----------------------
We have deferred the investment tax credit associated with our regulated utility
business and assets previously held by our regulated utility business in our
Consolidated Balance Sheets. The investment tax credit is amortized evenly to
income over the life of each property. We reduce income tax expense in our
Consolidated Statements of Income for the investment tax credit and other tax
credits associated with our nonregulated businesses, other than leveraged
leases.
Deferred Income Tax Assets and Liabilities
- ------------------------------------------
We must report some of our revenues and expenses differently for our financial
statements than for income tax return purposes. The tax effects of the
differences in these items are reported as deferred income tax assets or
liabilities in our Consolidated Balance Sheets. We measure the deferred income
tax assets and liabilities using income tax rates that are currently in effect.
A portion of our total deferred income tax liability relates to our
regulated utility business, but has not been reflected in the rates we charge
our customers. We refer to this portion of the liability as "Income taxes
recoverable through future rates (net)." We have recorded that portion of the
net liability as a regulatory asset in our Consolidated Balance Sheets. We
discuss this further in Note 6 on page 25.
State and Local Taxes
- ---------------------
As discussed in Note 5 on page 23, tax legislation has made comprehensive
changes to the state and local taxation of electric and gas utilities. State and
local income taxes are included in "Income taxes" in our Consolidated Statements
of Income.
Through December 31, 1999, we paid Maryland public service company franchise
tax on our utility revenue from sales in Maryland instead of state income tax.
We include the franchise tax in "Taxes other than income taxes" in our
Consolidated Statements of Income.
Cash and Cash Equivalents
- -------------------------
All highly liquid investments with original maturities of three months or less
are considered cash equivalents.
At December 31, 2000, $112.5 million of the cash balance included in our
Consolidated Balance Sheets was restricted under certain collateral arrangements
for our power marketing operation.
Inventory
- ---------
We record our fuel stocks and materials and supplies at the lower of cost or
market. We determine cost using the average cost method.
14
Real Estate Projects and Investments
- ------------------------------------
In Note 4 on page 22, we summarize the real estate projects and investments that
are in our Consolidated Balance Sheets. The projects and investments primarily
consist of:
o approximately 1,600 acres of land holdings in various stages of
development located at 11 sites in the central Maryland region,
o a 4,500 unit mixed-use planned unit development located in Anne Arundel
County, Maryland of which 1,300 residential units and 11 acres for
commercial development remain,
o an operating waste water treatment plant located in Anne Arundel
County, Maryland, and
o an equity interest in Corporate Office Properties Trust, a real estate
investment trust.
The costs incurred to acquire and develop properties are included as part of
the cost of the properties.
Financial Investments and Trading Securities
- --------------------------------------------
In Note 4 on page 22, we summarize the financial investments that are in our
Consolidated Balance Sheets.
SFAS No. 115, Accounting for Certain Investments in Debt and Equity
Securities, applies particular requirements to some of our investments in debt
and equity securities. We report those investments at fair value, and we use
either specific identification or average cost to determine their cost for
computing realized gains or losses. We classify these investments as either
trading securities or available-for-sale securities, which we describe
separately below. We report investments that are not covered by SFAS No. 115 at
their cost.
Trading Securities
- ------------------
Our other nonregulated businesses classify some of their investments in
marketable equity securities and financial limited partnerships as trading
securities. We include any unrealized gains or losses on these securities in
"Nonregulated revenues" in our Consolidated Statements of Income.
Available-for-Sale Securities
- -----------------------------
We classify our investments in the nuclear decommissioning trust funds as
available-for-sale securities. We describe the nuclear decommissioning trusts
and the reserves under the heading "Nuclear Decommissioning" later in this note.
In addition, our other nonregulated businesses classify some of their
investments in marketable equity securities as available-for-sale securities,
including the investment in Orion Power Holdings, Inc. (Orion) effective June 1,
2001. We discuss the accounting for the investment in Orion in more detail in
Note 4 on page 22.
We include any unrealized gains or losses on our available-for-sale
securities in "Accumulated other comprehensive income" in our Consolidated
Statements of Common Shareholders' Equity and Consolidated Statements of
Capitalization.
Evaluation of Assets for Impairment and Other Than Temporary Decline in Value
- -----------------------------------------------------------------------------
SFAS No. 121, Accounting for the Impairment of Long-Lived Assets and for
Long-Lived Assets to Be Disposed Of, requires us to evaluate certain assets that
have long lives (generating property and equipment and real estate) to determine
if they are impaired if certain conditions exist. We determine if long-lived
assets are impaired by comparing their undiscounted expected future cash flows
to their carrying amount in our accounting records. We would record an
impairment loss if the undiscounted expected future cash flows from an asset
were less than the carrying amount of the asset. Additionally, we evaluate our
equity-method investments to determine whether they have experienced a loss in
value that is considered other than a temporary decline in value.
We use our best estimates in making these evaluations and consider various
factors, including forward price curves for energy, fuel costs, and operating
costs. However, actual future market prices and project costs could vary from
those used in our impairment evaluations, and the impact of such variations
could be material.
Property, Plant and Equipment, Depreciation, Amortization, and Decommissioning
- ------------------------------------------------------------------------------
We report our property, plant and equipment at its original cost, unless
impaired under the provisions of SFAS No. 121.
Our original costs include:
o material and labor,
o contractor costs, and
o construction overhead costs and financing costs (where applicable).
We own an undivided interest in the Keystone and Conemaugh electric
generating plants in Western Pennsylvania, as well as in the transmission line
that transports the plants' output to the joint owners' service territories. Our
ownership interests in these plants are 20.99% in Keystone and 10.56% in
Conemaugh. These ownership interests represented a net investment of $150
million at December 31, 2001 and $143 million at December 31, 2000.
The "Nonregulated generation property, plant and equipment" in our
Consolidated Balance Sheets includes nonregulated generation construction work
in progress of $1,158.6 million at December 31, 2001 and $908.7 million at
December 31, 2000.
When we retire or dispose of property, plant and equipment, we remove the
asset's cost from our Consolidated Balance Sheets. We charge this cost to
accumulated depreciation for assets that were depreciated under the composite,
straight-line method. This includes regulated utility property, plant and
equipment and nonregulated generating assets previously owned by the regulated
utility. For all other assets, we remove the accumulated depreciation and
amortization amounts from our Consolidated Balance Sheets and record any gain or
loss in our Consolidated Statements of Income.
The costs of maintenance and certain replacements are charged to "Operating
expenses" in our Consolidated Statements of Income as incurred.
15
Depreciation Expense
- --------------------
We compute depreciation for our generating, electric transmission and
distribution, and gas facilities over the estimated useful lives of depreciable
property using either the:
o composite, straight-line rates (approved by the Maryland PSC for our
regulated utility business) applied to the average investment in classes
of depreciable property based on an average rate of approximately three
percent per year, or
o units of production method.
Other assets are depreciated using the straight-line method and the
following estimated useful lives:
Asset Estimated Useful Lives
- ----------------------------------------------------------
Building and improvements 20 - 50 years
Transportation equipment 5 - 15 years
Office equipment and computer
software 3 - 20 years
Amortization Expense
- --------------------
Amortization is an accounting process of reducing an amount in our Consolidated
Balance Sheets evenly over a period of time that approximates the useful life of
the related item. When we reduce amounts in our Consolidated Balance Sheets, we
increase amortization expense in our Consolidated Statements of Income. An
amount is considered fully amortized when it has been reduced to zero.
Nuclear Fuel
- ------------
We amortize nuclear fuel based on the energy produced over the life of the fuel
including the quarterly fees we pay to the Department of Energy for the future
disposal of spent nuclear fuel. These fees are based on the kilowatt-hours of
electricity sold. We report the amortization expense for nuclear fuel in
"Operating expenses" in our Consolidated Statements of Income.
Nuclear Decommissioning
- -----------------------
We record an expense and a reserve for the costs expected to be incurred in the
future to decommission the radioactive portion of Calvert Cliffs based on a
sinking fund methodology. The accumulated decommissioning reserve is recorded in
"Accumulated depreciation" in our Consolidated Balance Sheets. The total reserve
was $304.6 million at December 31, 2001 and $275.4 million at December 31, 2000.
Our contributions to the nuclear decommissioning trust funds were $22.0 million
for 2001, $13.2 million for 2000, and $17.6 million for 1999.
Under the Maryland PSC's order deregulating electric generation, BGE's
customers must pay a total of $520 million in 1993 dollars, adjusted for
inflation, to decommission Calvert Cliffs. BGE is collecting this amount on
behalf of and passing it to Calvert Cliffs Nuclear Power Plant, Inc. Calvert
Cliffs Nuclear Power Plant, Inc. is responsible for any difference between this
amount and the actual costs to decommission the plant.
We recorded a reserve for the costs expected to be incurred in the future to
decommission the radioactive portion of Nine Mile Point under the discounted
future cash flows methodology. The total reserve was $224.4 million at December
31, 2001. We have determined that the decommissioning trust funds established
for Nine Mile Point are adequately funded to cover the future costs to
decommission the radioactive portions of the plant and as such, no contributions
were made to the trust funds during the year ended December 31, 2001.
In accordance with Nuclear Regulatory Commission (NRC) regulations, we
maintain external decommissioning trusts to fund the costs expected to be
incurred to decommission Calvert Cliffs and Nine Mile Point. The assets in the
trusts are reported in "Nuclear decommissioning trust funds" in our Consolidated
Balance Sheets. The NRC requires utilities to provide financial assurance that
they will accumulate sufficient funds to pay for the cost of nuclear
decommissioning based upon either a generic NRC formula or a facility-specific
decommissioning cost estimate. We use the facility-specific cost estimate for
funding these costs and providing the required financial assurance.
We classify the investments in the nuclear decommissioning trust funds as
available-for-sale securities, and we report these investments at fair value in
our Consolidated Balance Sheets as previously discussed in this note.
As owners of Calvert Cliffs Nuclear Power Plant, we are required, along with
other domestic utilities, by the Energy Policy Act of 1992 to make contributions
to a fund for decommissioning and decontaminating the Department of Energy's
uranium enrichment facilities. The contributions are generally payable over 15
years with escalation for inflation and are based upon the proportionate amount
of uranium enriched by the Department of Energy for each utility. We amortize
the deferred costs of decommissioning and decontaminating the Department of
Energy's uranium enrichment facilities. The previous owners retained the
obligation for Nine Mile Point.
Capitalized Interest and Allowance for Funds Used During Construction
- ---------------------------------------------------------------------
Capitalized Interest
- --------------------
With the issuance of the Restructuring Order, we ceased accruing AFC (discussed
below) for electric generation-related construction projects.
Our nonregulated businesses capitalize interest costs under SFAS No. 34,
Capitalizing Interest Costs, for costs incurred to finance our power plant
construction projects and real estate developed for internal use.
Allowance for Funds Used During Construction (AFC)
- --------------------------------------------------
We finance regulated utility construction projects with borrowed funds and
equity funds. We are allowed by the Maryland PSC to record the costs of these
funds as part of the cost of construction projects in our Consolidated Balance
Sheets. We do this through the AFC, which we calculate using a rate authorized
by the Maryland PSC. We bill our customers for the AFC plus a return after the
utility property is placed in service.
The AFC rates are 9.4% for electric plant, 8.6% for gas plant, and 9.2% for
common plant. We compound AFC annually.
16
Long-Term Debt
- --------------
We defer all costs related to the issuance of long-term debt. These costs
include underwriters' commissions, discounts or premiums, other costs such as
legal, accounting, and regulatory fees, and printing costs. We amortize these
costs to expense over the life of the debt.
When we incur gains or losses on debt that we retire prior to maturity in
our regulated utility business, we amortize those gains or losses over the
remaining original life of the debt.
Use of Accounting Estimates
- ---------------------------
Management makes estimates and assumptions when preparing financial statements
under accounting principles generally accepted in the United States of America.
These estimates and assumptions affect various matters, including:
o our reported amounts of assets and liabilities in our Consolidated
Balance Sheets at the dates of the financial statements,
o our disclosure of contingent assets and liabilities at the dates of the
financial statements, and
o our reported amounts of revenues and expenses in our Consolidated
Statements of Income during the reporting periods.
These estimates involve judgments with respect to, among other things,
future economic factors that are difficult to predict and are beyond
management's control. As a result, actual amounts could differ from these
estimates.
Reclassifications
- -----------------
We have reclassified certain prior-year amounts for comparative purposes. These
reclassifications did not affect consolidated net income for the years
presented.
Accounting Standards Adopted
- ----------------------------
On January 1, 2001, we adopted SFAS No. 133, as amended by SFAS No. 138,
Accounting for Certain Derivative Instruments and Certain Hedging Activities.
These statements require that we recognize all derivatives on the balance
sheet at fair value. Changes in the value of derivatives that are not hedges
must be recorded in earnings.
We use derivatives in connection with our power marketing and risk
management activities and to hedge the risk of variations in future cash flows
from forecasted purchases and sales of electricity and gas in our electric
generation operations as more fully described in the Risk Management section on
page 13. Under SFAS No. 133, changes in the value of derivatives designated as
hedges that are effective in offsetting the variability in cash flows of
forecasted transactions are recognized in other comprehensive income until the
forecasted transactions occur. The ineffective portion of changes in fair value
of derivatives used as cash-flow hedges is immediately recognized in earnings.
In accordance with the transition provisions of SFAS No. 133, we recorded
the following at January 1, 2001:
o an $8.5 million after-tax cumulative effect adjustment that increased
earnings, and
o a $35.5 million after-tax cumulative effect adjustment that reduced other
comprehensive income.
The cumulative effect adjustment recorded in earnings represents the fair
value as of January 1, 2001 of a warrant for 705,900 shares of common stock of
Orion. The warrant had an exercise price of $10 per share and was received in
conjunction with our investment in Orion. As part of the sale of Orion to
Reliant Resources, Inc., we received cash equal to the difference between
Reliant's purchase price of $26.80 per share and the exercise price multiplied
by the number of shares subject to the warrant.
The cumulative effect adjustment recorded in other comprehensive income
represents certain forward sales of electricity that we designated as cash-flow
hedges of forecasted transactions primarily through our merchant energy
business.
Recently Issued Accounting Standards
- ------------------------------------
In 2001, the FASB issued SFAS No. 141, Business Combinations, SFAS No. 142,
Goodwill and Other Intangible Assets, SFAS No. 143, Accounting for Obligations
Associated with the Retirement of Long-Lived Assets, and SFAS No. 144,
Accounting for the Impairment or Disposal of Long-Lived Assets.
SFAS No. 141 requires all business combinations to be accounted for under
the purchase method. Use of the pooling-of-interests method is prohibited for
business combinations initiated after June 30, 2001. This statement also
establishes criteria for the separate recognition of intangible assets acquired
in a business combination. We do not expect the adoption of this statement to
have a material impact on our financial results.
SFAS No. 142 requires that goodwill no longer be amortized to earnings, but
instead be subject to periodic testing for impairment. This statement is
effective for fiscal years beginning after December 15, 2001, with earlier
application permitted only in specified circumstances. We do not expect the
adoption of this statement to have a material impact on our financial results.
SFAS No. 143 provides the accounting requirements for asset retirement
obligations associated with tangible long-lived assets. This statement is
effective for fiscal years beginning after June 15, 2002, and early adoption is
permitted. Currently, we are evaluating this statement and have not determined
its impact on our financial results, however, it could be material.
SFAS No. 144 replaces FASB Statement No. 121, Accounting for the Impairment
of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of. SFAS No. 144
addresses financial reporting for the impairment or disposal of long-lived
assets. This statement is effective for fiscal years beginning after December
15, 2001, and interim periods within those fiscal years, with early application
encouraged. We do not expect the adoption of this statement to have a material
impact on our financial results. However, we expect to reclassify our
senior-living facilities business as a discontinued operation in the first
quarter of 2002 as required under this standard.
17
Note 2. Contract Termination, Workforce Reduction, and Other Special Costs
- --------------------------------------------------------------------------------
2001 Events
- -----------
Pre-Tax After-Tax
- -------------------------------------------------------------------
(In millions)
Workforce reduction costs:
Voluntary termination benefits - VSERP $70.1 $42.5
Settlement and curtailment charges 16.3 9.9
Involuntary severance accrual 19.3 11.7
- -------------------------------------------------------------------
Total workforce reduction costs 105.7 64.1
Contract termination related costs 224.8 139.6
Impairment losses and other costs:
Loss on sale of Guatemalan operation 43.3 28.1
Impairments of real estate,
senior-living and international
investments 107.3 69.7
Cancellation of domestic power
projects 46.9 30.5
Reduction of financial investment 4.6 2.8
- -------------------------------------------------------------------
Total impairment losses and other costs 202.1 131.1
- -------------------------------------------------------------------
Total special costs $532.6 $334.8
===================================================================
Workforce Reduction Costs
- -------------------------
Voluntary Special Early Retirement Programs - VSERP
- ---------------------------------------------------
In the fourth quarter of 2001, we undertook several measures to reduce our
workforce through both voluntary and involuntary means. The purpose of these
programs was to reduce our operating costs to become more competitive. We
offered several Voluntary Special Early Retirement Programs (VSERP) to employees
of Constellation Energy and certain subsidiaries. The first group of these
programs offered enhanced early retirement benefits to employees age 55 or older
with 10 or more years of service. The second group of these programs offered
enhanced early retirement benefits to employees age 50 to 54 with 20 or more
years of service.
Since employees electing to participate in the age 55 or older VSERP had to
make their elections by the end of 2001, the cost of that program was reflected
in 2001. The $70.1 million in the above table reflects the portion of the total
cost of that program charged to expense for the 507 employees that elected to
participate. BGE recorded $37.9 million of this amount. BGE also recorded $13.7
million on its balance sheet as a regulatory asset related to its gas business
as discussed in Note 6 on page 25.
Settlement and Curtailment Charges
- ----------------------------------
In connection with the age 55 or older VSERP, a significant number of the
participants in our nonqualified pension plans are retiring. As a result, we
recognized a settlement loss of approximately $10.5 million and a curtailment
loss of approximately $5.8 million for those plans in accordance with SFAS No.
88, Employers' Accounting for Settlements and Curtailments of Defined Benefit
Pension Plans and for Termination Benefits. BGE recorded $6.6 million of this
amount. Additional details on the VSERP and their impact on our pension and
postretirement benefit plans are discussed in Note 7 on page 26.
Involuntary Severance Accrual
- -----------------------------
The voluntary programs were designed, offered, and timed to minimize the number
of employees who will be involuntarily severed under our overall workforce
reduction plan. Our workforce reduction plan identified 435 jobs to be
eliminated over and above position reductions expected to be satisfied through
the age 55 and over VSERP and was specific as to company, organizational unit,
and position. However, the number of employees that will elect to voluntarily
retire under the age 50 to 54 VSERP and how many will thereafter be
involuntarily severed is unknown until after the election period of the VSERP
ends in February 2002.
In accordance with EITF 94-3, Liability Recognition for Certain Employee
Termination Benefits and Other Costs to Exit an Activity (including Certain
Costs Incurred in a Restructuring), the Company recognized a liability of $25.1
million at December 31, 2001 for the targeted number of involuntary terminations
that will result if no employees elect the age 50 to 54 VSERP. The $19.3 million
in the table above represents involuntary severance charged to expense in 2001
in connection with our workforce reduction programs. BGE recorded $12.5 million
of this amount. BGE also recorded $5.8 million on its balance sheet as a
regulatory asset related to its gas business as discussed in Note 6 on page 25.
We will record any additional cost in excess of the 2001 involuntary severance
accrual for those eligible participants that elect the 50 to 54 VSERP in 2002.
Contract Termination Related Costs
- ----------------------------------
On October 26, 2001, we announced the decision to remain a single company and
canceled prior plans to separate our merchant energy business from our remaining
businesses.
We also announced the termination of our power business services agreement
with Goldman Sachs. We paid Goldman Sachs a total of $355 million, representing
$196.7 million to terminate the power business services agreement with our power
marketing operation and $159 million previously recognized as a payable for
services rendered under the agreement. Goldman Sachs also will not make an
equity investment in our merchant energy business as previously announced.
In addition, we terminated a software agreement we had whereby Goldman Sachs
would provide maintenance, support, and minor upgrades to our risk management
and trading system. We recognized $17.6 million in expense in the fourth quarter
of 2001 representing the unamortized prepaid costs related to this agreement.
Finally, we incurred approximately $10.5 million in employee-related expenses
and advisory costs from investment bankers and legal counsel. In total, we
recognized expenses of approximately $224.8 million in the fourth quarter of
2001 relating to the termination of our relationship with Goldman Sachs and our
decision not to separate.
18
Impairment Losses and Other Costs
- ---------------------------------
Sale of Guatemalan Operation
- ----------------------------
On November 8, 2001, we sold our Guatemalan power plant operations to an
affiliate of Duke Energy International, LLC, the international business unit of
Duke Energy. Through this sale, Duke Energy acquired Grupo Generador de
Guatemala y Cia., S.C.A., which owns two generating plants at Esquintla and Lake
Amatitlan in Guatemala. The combined capacity of the plants is 167 megawatts. We
decided to sell our Guatemalan operations to focus our efforts on our core
energy businesses. As a result of this transaction, we are no longer committed
to making significant future capital investments in a non-core operation. We
recorded a $43.3 million loss on this sale.
Impairments of Real Estate, Senior-Living, and Other International Investments
- ------------------------------------------------------------------------------
In the fourth quarter of 2001, our other nonregulated businesses recorded $107.3
million in impairments of certain real estate projects, senior-living
facilities, and international assets to reflect the fair value of these
investments. These investments represent non-core assets with a book value of
approximately $140.6 million after these impairments. As part of our focus on
capital and cash requirements and on our core energy businesses, the following
occurred:
o We decided to sell six real estate projects without further development
and all of our 18 senior-living facilities in 2002 and accelerate the
exit strategies for two other real estate projects that we will continue
to hold and own over the next several years. The real estate projects
include approximately 1,300 acres of land holdings in various stages of
development located in seven sites in the central Maryland region and an
operating waste water treatment plant located in Anne Arundel County,
Maryland.
o We decided to accelerate the exit strategy for our interest in a
Panamanian electric distribution company. As a non-core asset, management
has decided to reduce the cost and risk of holding this asset
indefinitely and intends to dispose of this asset. We believe a sale of
this investment can be completed by mid-to-late 2003.
o We incurred an other than temporary decline in our equity method
investment in the Bolivian Generating Group, which owns an interest in an
electric generation concession in Bolivia. This decline in value resulted
from a deterioration of our investment's position in the dispatch curve
of its capacity market. As a result, we recorded the impairment in
accordance with the provisions of Accounting Principles Board Opinion No.
18, The Equity Method of Accounting for Investments in Common Stock.
The impairments of our real estate, senior-living facilities, and Panama
investments were recorded in accordance with the provisions of SFAS No. 121.
These impairments resulted from our change from an intent to hold to an intent
to sell certain of these non-core assets in 2002, and our decision to limit
future costs and risks by accelerating the exit strategies for certain assets
that cannot be sold by the end of 2002. Previously, our strategy for these
investments was to hold them until we could obtain reasonable value. Under that
strategy, the expected cash flows were greater than our investment and no
impairment was recognized.
Impairment of Domestic Power Projects
- -------------------------------------
In the fourth quarter of 2001, our merchant energy business recorded impairments
of $46.9 million primarily due to $40.8 million in impairments under SFAS No.
121 associated with the termination of our planned development projects in
Texas, California, Florida, and Massachusetts that are not currently under
construction. The impairments include amounts paid for the purchase of four
turbines related to these development projects. We decided to terminate our
development projects due to the expected excess generation capacity in most
domestic markets and the significant decline in the forward market prices of
electricity. In accordance with the provisions of APB No. 18, we recognized $6.1
million for an other than temporary decline in the value of our investment in a
waste burning power plant in Michigan where operating cash flows are not
sufficient to pay existing debt service and we are not likely to recover our
equity interest in this investment.
Reduction of Financial Investment
- ---------------------------------
Our financial investments business recorded a $4.6 million reduction of its
investment in a leased aircraft due to the other than temporary decline in the
estimated residual value of used airplanes as a result of the September 11, 2001
terrorist attacks and the general downturn in the aviation industry. This
investment is accounted for as a leveraged lease under SFAS No. 13, Accounting
for Leases.
2000 Events
- -----------
In 2000, BGE offered a targeted VSERP to employees ages 55 or older with 10 or
more years of service in targeted positions that elected to retire on June 1,
2000 to reduce our operating costs to become more competitive. BGE recorded
approximately $10.0 million pre-tax for employees that elected to participate in
the program. Of this amount, BGE recorded approximately $3.0 million on its
balance sheet as a regulatory asset of its gas business. BGE is amortizing this
regulatory asset over a 5-year period as provided by the June 2000 Maryland PSC
gas base rate order as discussed in Note 6 on page 25. The remaining $7.0
million, or $4.2 million after-tax, related to BGE's electric business and was
charged to expense.
19
1999 Events
- -----------
Our generation operation recorded a $21.4 million pre-tax, or $14.2 million
after-tax, impairment of two geothermal power projects. These impairments
occurred because the expected future cash flows from the projects are less than
the investment in the projects. For the first project, this resulted from the
inability to restructure certain project agreements. For the second project, we
experienced a declining water temperature of the geothermal resource used by one
of the plants for production.
Our Latin American operation recorded a $7.1 million pre-tax, or $4.5
million after-tax, impairment to reflect the fair value of our investment in a
generating company in Bolivia as a result of our international exit strategy at
that time to focus on our core businesses.
Our financial investments operation exchanged its shares of common stock in
Capital Re, an insurance company, for common stock of ACE Limited (ACE) as part
of a business combination whereby ACE acquired all of the outstanding capital
stock of Capital Re. As a result, our financial investments operation wrote-down
its $94.2 million investment in Capital Re stock by $26.2 million pre-tax, or
$16.0 million after-tax, to reflect the closing price of the business
combination.
Our real estate and senior-living facilities operations entered into an
agreement to sell all but one of its senior-living facilities to Sunrise
Assisted Living, Inc. Under the terms of the agreement, Sunrise was to acquire
twelve of our existing senior-living facilities, three facilities under
construction, and several sites under development for $72.2 million in cash and
$16.0 million in debt assumption. We could not reach an agreement on financing
issues that subsequently arose, and the agreement was terminated in November
1999. However, our real estate and senior-living operations recorded a $9.6
million pre-tax, or $5.8 million after-tax, impairment related to the proposed
sale of these facilities.
Note 3. Information by Operating Segment
- --------------------------------------------------------------------------------
Our reportable operating segments are - Merchant Energy, Regulated Electric, and
Regulated Gas:
o Our nonregulated merchant energy business in North America:
- provides power marketing, origination transactions, and risk management
services,
- develops, owns, and operates generating facilities and/or power
projects in North America, and
- provides nuclear consulting services.
o Our regulated electric business purchases, distributes, and sells
electricity in Maryland.
o Our regulated gas business purchases, transports, and sells natural gas
in Maryland.
We have restated certain prior-period information for comparative purposes
based on our reportable operating segments.
Effective July 1, 2000, the financial results of the electric generation
portion of our business are included in the merchant energy business segment.
Prior to that date, the financial results of electric generation are included in
our regulated electric business.
Our remaining nonregulated businesses:
o provide energy products and services,
o sell and service electric and gas appliances, and heating and air
conditioning systems, engage in home improvements, and sell electricity
and natural gas through mass marketing efforts,
o provide cooling services,
o engage in financial investments,
o develop, own, and manage real estate and senior-living facilities, and
o own interests in Latin American power generation and distribution
projects and investments.
These reportable segments are strategic businesses based principally upon
regulations, products, and services that require different technology and
marketing strategies. We evaluate the performance of these segments based on net
income. We account for intersegment revenues using market prices. A summary of
information by operating segment is shown on the next page.
20
Unallocated
Merchant Regulated Regulated Other Corporate
Energy Electric Gas Nonregulated Items and
Business Business Business Businesses Eliminations Consolidated
------------- ------------- ------------ --------------- ------------ ---------------
(In millions)
2001
Unaffiliated revenues $ 614.3 $2,039.6 $674.3 $600.1 $ -- $3,928.3
Intersegment revenues 1,151.2 0.4 6.4 2.0 (1,160.0) --
- ---------------------------------- ------------- ------------- ------------ --------------- ------------ ---------------
Total revenues 1,765.5 2,040.0 680.7 602.1 (1,160.0) 3,928.3
Depreciation and amortization 174.9 173.3 47.7 23.2 -- 419.1
Fixed charges 25.8 135.8 28.5 48.7 -- 238.8
Income tax expense (benefit) 25.2 36.8 25.7 (49.8) -- 37.9
Cumulative effect of change in
accounting principle -- -- -- 8.5 -- 8.5
Net income (loss) (a) 93.1 50.9 37.5 (90.6) -- 90.9
Segment assets 8,134.3 3,764.9 1,104.2 1,314.0 (239.8) 14,077.6
Capital expenditures 1,815.0 180.3 58.7 35.0 -- 2,089.0
2000
Unaffiliated revenues $421.1 $2,134.7 $603.8 $692.9 $ -- $3,852.5
Intersegment revenues 604.6 0.5 7.8 20.4 (633.3) --
- ---------------------------------- ------------- ------------- ------------ --------------- ------------ ---------------
Total revenues 1,025.7 2,135.2 611.6 713.3 (633.3) 3,852.5
Depreciation and amortization 83.6 319.9 46.2 20.3 -- 470.0
Equity in income of
equity-method investees (b) -- 2.4 -- -- -- 2.4
Fixed charges 18.3 168.4 27.3 65.8 (8.4) 271.4
Income tax expense 118.5 72.2 21.9 17.5 -- 230.1
Net income (c) 198.6 102.3 30.6 13.8 -- 345.3
Segment assets 7,295.5 3,392.3 1,089.9 1,491.5 (329.9) 12,939.3
Capital expenditures 699.0 290.3 59.7 131.5 -- 1,180.5
1999
Unaffiliated revenues $277.3 $2,258.8 $ 476.5 $828.3 $ -- $3,840.9
Intersegment revenues -- 1.2 11.6 20.1 (32.9) --
- ---------------------------------- ------------- ------------- ------------ --------------- ------------ ---------------
Total revenues 277.3 2,260.0 488.1 848.4 (32.9) 3,840.9
Depreciation and amortization 7.5 376.4 44.9 21.0 -- 449.8
Equity in income of
equity-method investees (b) -- 5.1 -- -- -- 5.1
Fixed charges -- 174.2 26.1 56.1 (1.4) 255.0
Income tax expense (benefit) 29.2 149.2 18.1 (10.1) -- 186.4
Extraordinary loss -- 66.3 -- -- -- 66.3
Net income (loss) (d) 52.4 198.8 33.0 (24.1) -- 260.1
Segment assets 1,259.0 6,312.6 915.3 1,239.7 18.5 9,745.1
Capital expenditures 163.0 366.8 69.2 115.2 -- 714.2
(a) Our merchant energy business, our regulated electric business, our regulated
gas business, and our other nonregulated businesses recognized $197.9 million,
$33.7 million, $0.8 million, and $102.4 million, respectively, for workforce
reduction costs, contract termination related costs, and impairment losses and
other costs as described more fully in Note 2.
(b) Our merchant energy business records its equity in the income of equity
method investees in unaffiliated revenues.
(c) Our regulated electric business recorded expense of $4.2 million
related to employees that elected to participate in a Voluntary Special Early
Retirement Program. In addition, our merchant energy business recorded a $15.0
million deregulation transition cost incurred by our power marketing operation.
(d) Our regulated electric business recorded expense of $4.9 million related to
Hurricane Floyd. Our merchant energy business recorded $14.2 million for the
impairment of two geothermal power plants. Our Latin American operation recorded
$4.5 million for the impairment to reflect the fair value of our investment in a
power project in Bolivia. Our financial investments operation recorded $16.0
million for the reduction of its investment in Capital Re stock to reflect the
market value of this investment. Our real estate and senior-living facilities
operation recorded $5.8 million for the impairment of certain senior-living
facilities.
21
Note 4. Investments
- --------------------------------------------------------------------------------
Real Estate Projects and Investments
- ------------------------------------
Real estate projects and investments held by Constellation Real Estate Group
(CREG), consist of the following:
At December 31, 2001 2000
- ---------------------------------- ------------- -------------
(In millions)
Properties under development $100.5 $165.1
Operating properties
(net of accumulated
depreciation) 0.9 12.7
Equity interest in real estate
investments 109.3 112.5
- ---------------------------------- ------------- -------------
Total real estate projects and
investments $210.7 $290.3
================================== ============= =============
See Note 2 on page 18 for a discussion of impairments in 2001.
Power Projects
- --------------
Investments in power projects held by our merchant energy business consist of
the following:
At December 31, 2001 2000
- ---------------------------------- ------------- -------------
(In millions)
Equity Method $480.3 $488.4
Cost Method 10.7 10.8
- ---------------------------------- ------------- -------------
Total power projects $491.0 $499.2
================================== ============= =============
Our percentage voting interest in power projects accounted for under the
equity method ranges from 16% to 50%. Equity in earnings of these power projects
were $24.2 million in 2001, $50.2 million in 2000, and $49.7 million in 1999.
Our power projects accounted for under the equity method include investments
of $296.4 million in 2001 and $297.9 million in 2000 that sell electricity in
California under power purchase agreements called "Interim Standard Offer No. 4"
agreements. We discuss these projects further in Note 11 on page 36.
Our Latin American operation held power projects of $8.1 million at December
31, 2001 and $11.4 million at December 31, 2000.
See Note 2 on page 18 for a discussion of impairments recorded in 2001.
Orion and Financial Investments
- -------------------------------
Financial investments consist of the following:
At December 31, 2001 2000
- ---------------------------------- ------------- -------------
(In millions)
Orion $442.5 $192.0
Marketable equity securities 20.2 105.9
Financial limited partnerships 25.8 32.7
Leveraged leases 14.7 22.4
- ---------------------------------- ------------- -------------
Total financial investments $503.2 $353.0
================================== ============= =============
Investments Classified as Available-for-Sale
- --------------------------------------------
We classify the following investments as available-for-sale:
o nuclear decommissioning trust funds,
o our other nonregulated businesses' marketable equity securities
(shown above), and
o Orion.
This means we do not expect to hold them to maturity, and we do not consider
them trading securities.
Effective June 1, 2001, we changed our accounting for the investment in
Orion from the equity method to the cost method. This change resulted from no
longer having significant influence as required under equity method accounting
due to a reduction in our ownership percentage. Our ownership percentage
decreased due to Orion's issuance of 13 million shares of common stock that were
sold in a public offering and due to our sale of one million shares as part of
the offering. At December 31, 2001, the unrealized gain on our investment in
Orion was $244.0 million. In addition, at December 31, 2001, we owned a warrant
for 705,900 shares of common stock in Orion with a fair market value of $11.8
million. These warrants are accounted for under SFAS No. 133 as discussed in
Note 1 on page 17.
We show the fair values, gross unrealized gains and losses, and amortized
cost bases for all of our available-for-sale securities, in the following
tables. We use specific identification to determine cost in computing realized
gains and losses, except we use average cost basis for our investment in Orion.
At December 31, Amortized Unrealized Unrealized Fair
2001 Cost Basis Gains Losses Value
- -------------------- ---------- ---------- ---------- --------
(In millions)
Marketable equity
securities $773.9 $270.6 $(10.3) $1,034.2
Corporate debt and
U.S. Government
agency 47.7 1.5 -- 49.2
State municipal
bonds 38.4 3.3 (0.2) 41.5
- -------------------- ---------- ---------- ---------- --------
Totals $860.0 $275.4 $(10.5) $1,124.9
==================== ========== ========== ========== ========
At December 31, Amortized Unrealized Unrealized Fair
2000 Cost Basis Gains Losses Value
- -------------------- ----------- ---------- ---------- --------
(In millions)
Marketable equity
securities $171.8 $68.9 $(2.2) $238.5
Corporate debt and
U.S. Government
agency 26.1 0.1 (0.1) 26.1
State municipal
bonds 61.3 2.3 (0.4) 63.2
- -------------------- ----------- ---------- ---------- --------
Totals $259.2 $71.3 $(2.7) $327.8
==================== =========== ========== ========== ========
22
In addition to the above securities, the nuclear decommissioning trust funds
included $7.7 million at December 31, 2001 and $6.8 million at December 31, 2000
of cash and cash equivalents.
The preceding tables include $21.0 million in 2001 and $34.7 million in 2000
of unrealized net gains associated with the nuclear decommissioning trust funds
that are reflected as a change in the nuclear decommissioning trust funds on the
Consolidated Balance Sheets.
Gross and net realized gains and losses on available-for-sale securities
were as follows:
2001 2000 1999
- ---------------------------- --------- --------- ---------
(In millions)
Gross realized gains $47.6 $54.5 $ 11.7
Gross realized losses (7.9) (8.0) (38.8)
- ---------------------------- --------- --------- ---------
Net realized gains (losses) $39.7 $46.5 $(27.1)
============================ ========= ========= =========
The corporate debt securities, U.S. Government agency obligations, and state
municipal bonds mature on the following schedule:
At December 31, 2001 Amount
- ------------------------------------ -------------------------
(In millions)
Less than 1 year $ 8.4
1-5 years 34.3
5-10 years 22.2
More than 10 years 25.8
- ------------------------------------ -------------------------
Total maturities of debt securities $90.7
==================================== =========================
Note 5. Rate Matters and Accounting Impacts of Deregulation
- --------------------------------------------------------------------------------
On April 8, 1999, Maryland enacted the Electric Customer Choice and Competition
Act of 1999 (the "Act") and accompanying tax legislation that significantly
restructured Maryland's electric utility industry and modified the industry's
tax structure. In the Restructuring Order discussed below, the Maryland PSC
addressed the major provisions of the Act.
The tax legislation made comprehensive changes to the state and local
taxation of electric and gas utilities. Effective January 1, 2000, the Maryland
public service franchise tax was altered to generally include a tax equal to
.062 cents on each kilowatt-hour of electricity and .402 cents on each therm of
natural gas delivered for final consumption in Maryland. The Maryland 2%
franchise tax on electric and natural gas utilities continues to apply to
transmission and distribution revenue. Additionally, all electric and natural
gas utility results are subject to the Maryland corporate income tax.
Beginning July 1, 2000, the tax legislation also provided for a two-year
phase-in of a 50% reduction in the local personal property taxes on machinery
and equipment used to generate electricity for resale and a 60% corporate income
tax credit for real property taxes paid on those facilities.
On November 10, 1999, the Maryland PSC issued a Restructuring Order that
resolved the major issues surrounding electric restructuring, accelerated the
timetable for customer choice, and addressed the major provisions of the Act.
The Restructuring Order also resolved the electric restructuring proceeding
(transition costs, customer price protections, and unbundled rates for electric
services) and a petition filed in September 1998 by the Office of People's
Counsel (OPC) to lower our electric base rates. The major provisions of the
Restructuring Order are:
o All customers, except a few commercial and industrial companies that have
signed contracts with BGE, can choose their electric energy supplier
beginning July 1, 2000. BGE will provide a standard offer service for
customers that do not select an alternative supplier. In either case, BGE
will continue to deliver electricity to all customers in areas
traditionally served by BGE.
o BGE reduced residential base rates by approximately 6.5%, on average
about $54 million a year, beginning July 1, 2000. These rates will not
change before July 2006.
o Commercial and industrial customers have up to four service options
that will fix electric energy rates and transition charges for a period
that ends in 2004 to 2006.
o BGE's electric fuel rate clause was discontinued effective July 1, 2000.
o Electric delivery service rates are frozen through June 2004 for
commercial and industrial customers. The generation and transmission
components of rates are frozen for different time periods depending on
the service options selected by those customers.
o BGE collects $528 million after-tax of its potentially stranded
investments and utility restructuring costs through a competitive
transition charge on its customers' bills. Residential customers will pay
this charge through 2006. Commercial and industrial customers will pay in
a lump sum or over a period ending in 2004 to 2006, depending on the
service option selected by each customer.
o Generation-related regulatory assets and nuclear decommissioning costs
are included in delivery service rates effective July 1, 2000 and will be
recovered on a basis approximating their amortization schedules prior to
July 1, 2000.
23
o Effective July 1, 2000, BGE unbundled rates to show separate components
for delivery service, competitive transition charges, standard offer
services (generation), transmission, universal service, and taxes.
o Effective July 1, 2000, BGE transferred, at book value, its ten
Maryland-based fossil and nuclear power plants and its partial ownership
interest in two coal plants and a hydroelectric plant in Pennsylvania to
nonregulated subsidiaries of Constellation Energy.
o BGE reduced its generation assets by $150 million pre-tax during the
period July 1, 1999 - June 30, 2000 to mitigate a portion of BGE's
potentially stranded investments.
o Universal service is being provided for low-income customers without
increasing their bills. BGE will provide its share of a statewide fund
totaling $34 million annually.
As discussed in Note 1 on page 11, EITF 97-4 requires that a company should
cease applying SFAS No. 71 when either legislation is passed or a regulatory
body issues an order that contains sufficient detail to determine how the
transition plan will affect the deregulated portion of the business.
Additionally, a company would continue to recognize regulatory assets and
liabilities in the Consolidated Balance Sheets to the extent that the transition
plan provides for their recovery.
We believe that the Restructuring Order provided sufficient details of the
transition plan to competition for BGE's electric generation business to require
BGE to discontinue the application of SFAS No. 71 for that portion of its
business. Accordingly, in the fourth quarter of 1999, we adopted the provisions
of SFAS No. 101 and EITF 97-4 for BGE's electric generation business.
SFAS No. 101 requires the elimination of the effects of rate regulation that
have been recognized as regulatory assets and liabilities pursuant to SFAS No.
71. However, EITF 97-4 requires that regulatory assets and liabilities that will
be recovered in the regulated portion of the business continue to be classified
as regulatory assets and liabilities. The Restructuring Order provided for the
creation of a single, new generation-related regulatory asset to be recovered
through BGE's regulated transmission and distribution business. We discuss this
further in Note 6 on page 25.
Pursuant to SFAS No. 101, the book value of property, plant, and equipment
may not be adjusted unless those assets are impaired under the provisions of
SFAS No. 121. The process we used in evaluating and measuring impairment under
the provisions of SFAS No. 121 involved two steps. First, we compared the net
book value of each generating plant to the estimated undiscounted future net
operating cash flows from that plant. An electric generating plant was
considered impaired when its undiscounted future net operating cash flows were
less than its net book value. Second, we computed the fair value of each plant
that is determined to be impaired based on the present value of that plant's
estimated future net operating cash flows discounted using an interest rate that
considers the risk of operating that facility in a competitive environment. To
the extent that the net book value of each impaired electric generation plant
exceeded its fair value, we reduced its book value.
Under the Restructuring Order, BGE will recover $528 million after-tax of
its potentially stranded investments and utility restructuring costs through the
competitive transition charge component of its customer rates beginning July 1,
2000. This recovery mostly relates to the stranded costs associated with the
Calvert Cliffs Nuclear Power Plant, whose book value was substantially higher
than its estimated fair value. However, Calvert Cliffs was not considered
impaired under the provisions of SFAS No. 121 since its estimated future
undiscounted cash flows exceeded its book value. Accordingly, BGE did not record
any impairment related to Calvert Cliffs. However, BGE recognized after-tax
impairment losses totaling $115.8 million associated with certain of its fossil
plants under the provisions of SFAS No. 121.
BGE had contracts to purchase electric capacity and energy that became
uneconomic upon the deregulation of electric generation. Therefore, BGE recorded
a $34.2 million after-tax charge based on the net present value of the excess of
estimated contract costs over the market-based revenues to recover these costs
over the remaining terms of the contracts. In addition, BGE had deferred certain
energy conservation expenditures that would not be recovered through its
transmission and distribution business under the Restructuring Order.
Accordingly, BGE recorded a $10.3 million after-tax charge to eliminate the
regulatory asset previously established for these deferred expenditures.
At December 31, 1999, the total charge for BGE's electric generating plants
that were impaired, losses on uneconomic purchased capacity and energy
contracts, and deferred energy conservation expenditures was approximately
$160.3 million after-tax.
BGE recorded approximately $94.0 million of the $160.3 million on its
balance sheet. This consisted of a $150.0 million regulatory asset of its
regulated transmission and distribution business, net of approximately $56.0
million of associated deferred income taxes. The regulatory asset was amortized
as it was recovered from ratepayers through June 30, 2000. This accomplished the
$150 million reduction of its generation plants required by the Restructuring
Order.
BGE recorded an after-tax, extraordinary charge against earnings for
approximately $66.3 million related to the remaining portion of the $160.3
million described above that was not recovered under the Restructuring Order.
24
Note 6. Regulatory Assets (net)
- --------------------------------------------------------------------------------
As discussed in Note 1 on page 11, the Maryland PSC provides the final
determination of the rates we charge our customers for our regulated businesses.
Generally, we use the same accounting policies and practices used by
nonregulated companies for financial reporting under accounting principles
generally accepted in the United States of America. However, sometimes the
Maryland PSC orders an accounting treatment different from that used by
nonregulated companies to determine the rates we charge our customers. When this
happens, we must defer certain utility expenses and income in our Consolidated
Balance Sheets as regulatory assets and liabilities. We then record them in our
Consolidated Statements of Income (using amortization) when we include them in
the rates we charge our customers.
We summarize regulatory assets and liabilities in the following table, and
we discuss each of them separately below.
At December 31, 2001 2000
- -------------------------------------- ---------- ----------
(In millions)
Electric generation-related
regulatory asset $249.0 $267.8
Income taxes recoverable through
future rates (net) 95.6 101.2
Deferred postretirement and
postemployment benefit costs 35.5 38.7
Deferred environmental costs 26.0 28.8
Deferred fuel costs (net) 33.5 71.1
Workforce reduction costs 21.6 2.8
Other (net) 2.6 4.5
- -------------------------------------- ---------- ----------
Total regulatory assets (net) $463.8 $514.9
====================================== ========== ==========
Electric Generation-Related Regulatory Asset
- --------------------------------------------
With the issuance of the Restructuring Order, BGE no longer met the requirements
for the application of SFAS No. 71 for the electric generation portion of its
business. In accordance with SFAS No. 101 and EITF 97-4, all individual
generation-related regulatory assets and liabilities must be eliminated from our
balance sheet unless these regulatory assets and liabilities will be recovered
in the regulated portion of the business. Pursuant to the Restructuring Order,
BGE wrote-off all of its individual, generation-related regulatory assets and
liabilities. BGE established a single, new generation-related regulatory asset
for amounts to be collected through its regulated transmission and distribution
business. The new regulatory asset is being amortized on a basis that
approximates the pre-existing individual regulatory asset amortization
schedules.
Income Taxes Recoverable Through Future Rates (net)
- ---------------------------------------------------
As described in Note 1 on page 14, income taxes recoverable through future rates
are the portion of our net deferred income tax liability that is applicable to
our regulated utility business, but has not been reflected in the rates we
charge our customers. These income taxes represent the tax effect of temporary
differences in depreciation and the allowance for equity funds used during
construction, offset by differences in deferred tax rates and deferred taxes on
deferred investment tax credits. We amortize these amounts as the temporary
differences reverse.
Deferred Postretirement and Postemployment Benefit Costs
- --------------------------------------------------------
Deferred postretirement and postemployment benefit costs are the costs we
recorded under SFAS No. 106 (for post-retirement benefits) and No. 112 (for
postemployment benefits) in excess of the costs we included in the rates we
charge our customers. We began amortizing these costs over a 15-year period in
1998. We discuss these costs further in Note 7 on page 26.
Deferred Environmental Costs
- ----------------------------
Deferred environmental costs are the estimated costs of investigating and
cleaning up contaminated sites we own. We discuss this further in Note 11 on
page 34. We are amortizing $21.6 million of these costs (the amount we had
incurred through October 1995) and $6.4 million of these costs (the amount we
incurred from November 1995 through June 2000) over 10-year periods in
accordance with the Maryland PSC's orders.
Deferred Fuel Costs
- -------------------
As described in Note 1 on page 12, deferred fuel costs are the difference
between our actual costs of electric fuel, net purchases and sales of
electricity, and natural gas, and our fuel rate revenues collected from
customers. We reduce deferred fuel costs as we collect them from or refund them
to our customers.
We show our deferred fuel costs in the following table.
At December 31, 2001 2000
- -------------------------------------- ---------- ----------
(In millions)
Electric $ -- $42.3
Gas 33.5 28.8
- -------------------------------------- ---------- ----------
Deferred fuel costs (net) $33.5 $71.1
====================================== ========== ==========
Under the terms of the Restructuring Order, BGE's electric fuel rate clause
was discontinued effective July 1, 2000. In September 2000, the Maryland PSC
approved the collection of the $54.6 million accumulated difference between our
actual costs of fuel and energy and the amounts collected from customers that
were deferred under the electric fuel rate clause through June 30, 2000. We
collected this accumulated difference from customers over the twelve-month
period ending October 2001.
Workforce Reduction Costs
- -------------------------
The portions of the workforce reduction costs associated with the VSERP and
involuntary severance programs we announced in 2001 and 2000 that relate to
BGE's gas business are deferred as regulatory assets in accordance with the
Maryland PSC's orders in prior rate cases. These costs are amortized over 5-year
periods. See Note 2 on page 18 and Note 7 on page 26.
25
Note 7. Pension, Postretirement, Other Postemployment, and Employee Savings
Plan Benefits
- --------------------------------------------------------------------------------
We offer pension, postretirement, other postemployment, and employee savings
plan benefits. We describe each of these separately below. Nine Mile Point
offers its own pension, postretirement, other postemployment, and employee
savings plan benefits to its employees. The benefits for Nine Mile Point are
included in the tables beginning on the next page.
Pension Benefits
- ----------------
We sponsor several defined benefit pension plans for our employees. These
include the basic, qualified plan that most employees participate in and several
nonqualified plans that are available only to certain employees. A defined
benefit plan specifies the amount of benefits a plan participant is to receive
using information about the participant. Employees do not contribute to these
plans. Generally, we calculate the benefits under these plans based on age,
years of service, and pay.
Sometimes we amend the plans retroactively. These retroactive plan
amendments require us to recalculate benefits related to participants' past
service. We amortize the change in the benefit costs from these plan amendments
on a straight-line basis over the average remaining service period of active
employees.
We fund the plans by contributing at least the minimum amount required under
Internal Revenue Service regulations. We calculate the amount of funding using
an actuarial method called the projected unit credit cost method. The assets in
all of the plans at December 31, 2001 were mostly marketable equity and fixed
income securities.
In 1999, we made the following amendments:
o eligible participants were allowed to choose between an enhanced
version of the current benefit formula and a new pension equity plan
(PEP) formula. Pension benefits for eligible employees hired after
December 31, 1999 are based on a PEP formula, and
o pension and survivor benefits were increased for participants who
retired prior to January 1, 1994 and for their surviving spouses.
The financial impacts of the amendments are included in the tables beginning
on the next page.
Postretirement Benefits
- -----------------------
We sponsor defined benefit postretirement health care and life insurance plans
that cover substantially all of our employees. Generally, we calculate the
benefits under these plans based on age, years of service, and pension benefit
levels. We do not fund these plans.
For nearly all of the health care plans, retirees make contributions to
cover a portion of the plan costs. Contributions for employees who retire after
June 30, 1992 are calculated based on age and years of service. The amount of
retiree contributions increases based on expected increases in medical costs.
For the life insurance plan, retirees do not make contributions to cover a
portion of the plan costs.
Effective January 1, 1993, we adopted SFAS No. 106, Employers' Accounting
for Postretirement Benefits Other Than Pensions. The adoption of that statement
caused:
o a transition obligation, which we are amortizing over 20 years, and
o an increase in annual postretirement benefit costs.
For our nonregulated businesses, we expense all postretirement benefit
costs. For our regulated utility business, we accounted for the increase in
annual postretirement benefit costs under two Maryland PSC rate orders:
o in an April 1993 rate order, the Maryland PSC allowed us to expense
one-half and defer, as a regulatory asset (see Note 6 on page 25), the
other half of the increase in annual postretirement benefit costs related
to our regulated electric and gas businesses, and
o in a November 1995 rate order, the Maryland PSC allowed us to expense
all of the increase in annual postretirement benefit costs related to our
regulated gas business.
Beginning in 1998, the Maryland PSC authorized us to:
o expense all of the increase in annual postretirement benefit costs
related to our regulated electric business, and
o amortize the regulatory asset for postretirement benefit costs related to
our regulated electric and gas businesses over 15 years.
VSERP
- -----
In 2001, our Board of Directors approved several voluntary retirement programs
for Constellation Energy and certain subsidiaries. The first group of these
programs offered enhanced early retirement benefits to employees age 55 or older
with 10 or more years of service. The second group of these programs offered
enhanced early retirement benefits to employees age 50 to 54 with 20 or more
years of service.
Since employees electing to participate in the age 55 or older VSERP had to
make their elections by the end of 2001, the cost of that program was reflected
in 2001. The total cost of that program was approximately $83.8 million ($63.5
million in pension termination benefits, $18.5 million in postretirement benefit
costs, and $1.8 million in education and outplacement assistance costs). Of this
amount, BGE recorded approximately $13.7 million on its balance sheet as a
regulatory asset of its gas business. This amount will be amortized over a
5-year period as provided for in prior Maryland PSC rate orders.
In connection with the retirement of a significant number of the
participants in the nonqualified pension plans we recognized a settlement loss
of approximately $10.5 million
26
and a curtailment loss of approximately $5.8 million for those plans in
accordance with SFAS No. 88.
Since the age 50 to 54 programs allow employees to make their elections
beginning in January through February 2002, the cost of that program will be
reflected in 2002.
We recorded a $133.0 million additional minimum pension liability adjustment
as a result of the combination of decreases in the fair value of plan assets due
to a declining equity market in 2001 and an increased pension liability
primarily due to the VSERP. We charged $59.0 million of this adjustment to an
intangible asset and included in "Other deferred charges" in our Consolidated
Balance Sheets. The remaining $74.0 million, or $44.7 million after-tax, of this
adjustment was included in "Accumulated other comprehensive income" in our
Consolidated Statements of Common Shareholders' Equity and Consolidated
Statements of Capitalization.
In 2000, we offered a targeted VSERP to provide enhanced early retirement
benefits to certain eligible participants in targeted jobs at BGE that elected
to retire on June 1, 2000. BGE recorded approximately $10.0 million ($7.6
million for pension termination benefits and $2.4 million for postretirement
benefit costs) for employees that elected to participate in the program. Of this
amount, BGE recorded approximately $3.0 million on its balance sheet as a
regulatory asset of its gas business. We amortize this regulatory asset over a
5-year period. The remaining $7.0 million related to BGE's electric business was
charged to expense.
The cost of the 2001 and 2000 voluntary retirement programs and the
settlement or curtailment losses are not included in the tables of net periodic
pension and postretirement benefit costs.
Obligations, Assets, and Funded Status
- --------------------------------------
We show the change in the benefit obligations, plan assets, and funded status of
the pension and postretirement benefit plans including the effect of the Nine
Mile Point acquisition, in the following tables.
Pension Postretirement
Benefits Benefits
2001 2000 2001 2000
- -------------------------- -------- --------- ------- --------
(In millions)
Change in benefit obligation
- ----------------------------
Benefit obligation at
January 1 $1,045.1 $1,016.7 $375.9 $358.7
Service cost 25.8 25.4 8.4 7.7
Interest cost 76.1 73.1 29.2 26.6
Plan participants'
contributions -- -- 3.0 2.8
Actuarial loss 42.6 0.8 49.1 40.9
Plan amendments -- 6.7 -- (41.1)
VSERP charge 63.5 7.6 18.5 2.4
Curtailment 9.7 -- -- --
Settlement (23.0) -- -- --
Nine Mile Point
acquisition 91.8 -- 15.0 --
Benefits paid (72.4) (85.2) (23.9) (22.1)
- ------------------------- --------- --------- ------- --------
Benefit obligation at
December 31 $1,259.2 $1,045.1 $475.2 $375.9
========================= ========= ========= ======= ========
Pension Postretirement
Benefits Benefits
2001 2000 2001 2000
- -------------------------- --------- -------- ------- --------
(In millions)
Change in plan assets
- ---------------------
Fair value of plan assets
at January 1 $1,030.1 $1,084.9 $ -- $ --
Actual return on
plan assets (42.7) 3.7 -- --
Employer contribution 39.4 26.7 20.9 19.3
Plan participants'
contributions -- -- 3.0 2.8
Benefits paid (72.4) (85.2) (23.9) (22.1)
- -------------------------- --------- -------- ------- --------
Fair value of plan assets
at December 31 $ 954.4 $1,030.1 $ -- $ --
========================== ========= ======== ======= ========
Pension Postretirement
Benefits Benefits
2001 2000 2001 2000
- ------------------------- ---------- -------- -------- ---------
(In millions)
Funded Status
- -------------
Funded Status at
December 31 $(304.8) $(15.0) $(475.2) $(375.9)
Unrecognized net
actuarial loss 207.8 49.2 107.8 61.4
Unrecognized prior
service cost 56.7 59.2 (0.4) (0.4)
Unrecognized
transition obligation -- -- 86.9 94.8
Unamortized net asset
from adoption of
SFAS No. 87 -- (0.2) -- --
Pension liability
adjustment (133.0) -- -- --
- ------------------------- ---------- -------- -------- ---------
(Accrued) prepaid
benefit cost $(173.3) $ 93.2 $(280.9) $(220.1)
========================= ========== ======== ======== =========
27
Net Periodic Benefit Cost
- -------------------------
We show the components of net periodic pension benefit cost in the following
table:
Year Ended December 31, 2001 2000 1999
- -------------------------------- --------- -------- ----------
(In millions)
Components of net periodic
- --------------------------
pension benefit cost
--------------------
Service cost $25.8 $25.4 $26.1
Interest cost 76.1 73.1 65.3
Expected return on plan assets (87.5) (83.6) (76.6)
Amortization of transition
obligation (0.2) (0.2) (0.2)
Amortization of prior
service cost 6.5 6.5 2.5
Recognized net actuarial loss 2.8 2.6 10.1
Amount capitalized as
construction cost (2.5) (3.4) (4.2)
- -------------------------------- --------- -------- ----------
Net periodic pension
benefit cost $21.0 $20.4 $23.0
================================ ========= ======== ==========
We show the components of net periodic postretirement benefit cost in the
following table:
Year Ended December 31, 2001 2000 1999
- -------------------------------- --------- -------- ----------
(In millions)
Components of net periodic
- --------------------------
postretirement benefit cost
---------------------------
Service cost $ 8.4 $ 7.7 $ 8.6
Interest cost 29.2 26.6 24.4
Amortization of transition
obligation 7.9 7.9 11.0
Recognized net actuarial loss 3.3 3.1 1.9
Amount capitalized as
construction cost (14.5) (10.8) (9.4)
- -------------------------------- --------- -------- ----------
Net periodic postretirement
benefit cost $34.3 $34.5 $36.5
================================ ========= ======== ==========
Assumptions
- -----------
We made the assumptions below to calculate our pension and postretirement
benefit obligations.
Pension Postretirement
Benefits Benefits
At December 31, 2001 2000 2001 2000
- ------------------------ ------- -------- -------- ---------
Discount rate 7.25% 7.50% 7.25% 7.50%
Expected return on
plan assets 9.00 9.00 N/A N/A
Rate of compensation
increase 4.00 4.00 4.00 4.00
We assumed the health care inflation rates to be:
o in 2001, 5.7% for Medicare-eligible retirees and 9.5% for retirees not
covered by Medicare, and
o in 2002, 11.0% for both Medicare-eligible retirees and retirees not
covered by Medicare.
After 2002, we assumed inflation rates will decrease to 7.0% in 2003, 6.5%
in 2004, 6.0% in 2005, and 5.5% annually after 2005.
A one-percent increase in the health care inflation rate from the assumed
rates would increase the accumulated postretirement benefit obligation by
approximately $63.8 million as of December 31, 2001 and would increase the
combined service and interest costs of the postretirement benefit cost by
approximately $5.9 million annually.
A one-percent decrease in the health care inflation rate from the assumed
rates would decrease the accumulated postretirement benefit obligation by
approximately $51.1 million as of December 31, 2001 and would decrease the
combined service and interest costs of the postretirement benefit cost by
approximately $4.7 million annually.
Other Postemployment Benefits
- -----------------------------
We provide the following postemployment benefits:
o health and life insurance benefits to eligible employees who are found to
be disabled under our Disability Insurance Plan, and
o income replacement payments for employees found to be disabled before
November 1995 (payments for employees found to be disabled after that
date are paid by an insurance company, and the cost is paid by
employees).
The liability for these benefits totaled $48.7 million as of December 31,
2001 and $46.7 million as of December 31, 2000.
Effective December 31, 1993, we adopted SFAS No. 112, Employers' Accounting
for Postemployment Benefits. We deferred, as a regulatory asset (see Note 6 on
page 25), the postemployment benefit liability attributable to our regulated
utility business as of December 31, 1993, consistent with the Maryland PSC's
orders for postretirement benefits (described earlier in this note).
We began to amortize the regulatory asset over 15 years beginning in 1998.
The Maryland PSC authorized us to reflect this change in our regulated electric
and gas base rates to recover the higher costs in 1998.
We assumed the discount rate for other postemployment benefits to be 5.0% in
2001 and 5.5% in 2000.
Employee Savings Plan Benefits
- ------------------------------
We, along with several of our subsidiaries, sponsor defined contribution savings
plans that are offered to all eligible employees of Constellation Energy and
certain employees of our subsidiaries. The Savings Plans are qualified 401(k)
plans under the Internal Revenue Code. In a defined contribution plan, the
benefits a participant is to receive result from regular contributions to a
participant account. Matching contributions to participant accounts are made
under these plans. Matching contributions to these plans were:
o $12.2 million in 2001,
o $10.8 million in 2000, and
o $10.4 million in 1999.
28
Note 8. Short-Term Borrowings
- --------------------------------------------------------------------------------
Our short-term borrowings may include bank loans, commercial paper, and bank
lines of credit. Short-term borrowings mature within one year from the date of
issuance. We pay commitment fees to banks for providing us lines of credit. When
we borrow under the lines of credit, we pay market interest rates.
Constellation Energy
- --------------------
In anticipation of separating our merchant energy business from our other
businesses and to fund working capital requirements and capital expenditures, in
June 2001, Constellation Energy arranged a $2.5 billion, 364-day revolving
credit facility. However, since we canceled prior plans to separate, we used
this facility primarily to fund capital expenditures, and working capital
requirements, including commercial paper support, for the merchant energy
business.
In June 2001, Constellation Energy also arranged a $380 million, 364-day
revolving credit facility to be used primarily to support letters of credit and
for other short-term financing needs, including commercial paper support.
Constellation Energy also has an existing $188.5 million, multi-year revolving
credit facility available for short-term and long-term needs, including support
for the issuance of letters of credit.
Constellation Energy had committed bank lines of credit as described above
of $3.1 billion at December 31, 2001 and $565.0 million at December 31, 2000 for
short-term financial needs, including support for the issuance of letters of
credit. These agreements also support Constellation Energy's commercial paper
program. Letters of credit issued under all of our facilities totaled $245.8
million at December 31, 2001 and $297.2 million at December 31, 2000.
Constellation Energy had commercial paper outstanding of $954.9 million at
December 31, 2001 and $198.7 million at December 31, 2000.
The weighted-average effective interest rates for Constellation Energy's
commercial paper were 3.73% for the year ended December 31, 2001 and 6.31% for
2000.
BGE
- ---
BGE had no commercial paper outstanding at December 31, 2001 and $32.1 million
at December 31, 2000.
At December 31, 2001, BGE had unused committed bank lines of credit totaling
$243.0 million supporting the commercial paper program compared to $218.0
million at December 31, 2000. BGE has a $25 million revolving credit agreement
that is available through 2003. At December 31, 2001 and 2000, BGE did not have
any borrowings under the revolving credit agreement. This agreement also
supports BGE's commercial paper program.
The weighted-average effective interest rates for BGE's commercial paper
were 2.53% for the year ended December 31, 2001 and 6.36% for 2000.
Other Nonregulated Businesses
- -----------------------------
Our other nonregulated businesses had short-term borrowings outstanding of $20.1
million at December 31, 2001 and $12.8 million at December 31, 2000. The
weighted-average effective interest rates for our other nonregulated businesses'
short-term borrowings were 4.20% for the year ended December 31, 2001 and 8.59%
for 2000.
Note 9. Long-Term Debt
- --------------------------------------------------------------------------------
Long-term debt matures in one year or more from the date of issuance. We
summarize our long-term debt in the Consolidated Statements of Capitalization.
As you read this section, it may be helpful to refer to those statements.
Constellation Energy
- --------------------
On January 17, 2001, we issued $400.0 million of Mandatorily Redeemable
Floating Rate Notes that matured on January 17, 2002.
On April 11, 2001, we issued $235.0 million of Mandatorily Redeemable
Floating Rate Notes that matured on January 17, 2002.
In 2001, we redeemed several Notes that totaled $700.0 million prior to
their maturity for a purchase price equal to 100% of their principal amount,
plus accrued interest.
BGE
- ---
BGE's First Refunding Mortgage Bonds
- ------------------------------------
BGE's first refunding mortgage bonds are secured by a mortgage lien on all of
its assets. The generating assets BGE transferred to subsidiaries of
Constellation Energy also remain subject to the lien of BGE's mortgage, along
with the stock of Safe Harbor Water Power Corporation and Constellation
Enterprises, Inc.
BGE is required to make an annual sinking fund payment each August 1 to the
mortgage trustee. The amount of the payment is equal to 1% of the highest
principal amount of bonds outstanding during the preceding 12 months. The
trustee uses these funds to retire bonds from any series through repurchases or
calls for early redemption. However, the trustee cannot call the following bonds
for early redemption:
o 7 1/4% Series, due 2002 o 5 1/2% Series, due 2004
o 6 1/2% Series, due 2003 o 7 1/2% Series, due 2007
o 6 1/8% Series, due 2003 o 6 5/8% Series, due 2008
29
Holders of the Remarketed Floating Rate Series due September 1, 2006 have
the option to require BGE to repurchase their bonds at face value on September 1
of each year. BGE is required to repurchase and retire at par any bonds that are
not remarketed or purchased by the remarketing agent. BGE also has the option
to redeem all or some of these bonds at face value each September 1.
BGE's Other Long-Term Debt
- --------------------------
On May 11, 2001, BGE issued $200.0 million of Floating Rate Reset Notes that
matured on February 5, 2002.
Also on May 11, 2001, BGE redeemed $200.0 million of Floating Rate Notes.
On December 11, 2001, BGE issued $300.0 million 5.25% Notes, due December
15, 2006.
On July 1, 2000, BGE transferred $278.0 million of tax-exempt debt to our
merchant energy business related to the transferred assets. At December 31,
2001, BGE remains contingently liable for the $276.5 million outstanding balance
of this debt.
On December 20, 2000, BGE issued $173.0 million of 6.75% Remarketable and
Redeemable Securities (ROARS) due December 15, 2012. The ROARS contain an option
for the underwriters to remarket the ROARS on December 15, 2002. If the
underwriters do not elect to remarket the ROARS on that date, then BGE must
redeem the ROARS at 100% of the principal amount on December 15, 2002.
We show the weighted-average interest rates and maturity dates for BGE's
fixed-rate medium-term notes outstanding at December 31, 2001 in the following
table.
Weighted-Average Maturity
Series Interest Rate Dates
- ------------------- ---------------------- -----------------
B 8.77% 2002-2006
C 7.97 2003
D 6.67 2004-2006
E 6.66 2006-2012
G 6.08 2008
Some of the medium-term notes include a "put option." These put options
allow the holders to sell their notes back to BGE on the put option dates at a
price equal to 100% of the principal amount. The following is a summary of
medium-term notes with put options.
Series E Notes Principal Put Option Dates
- ------------------------ -------------- --------------------
(In millions)
6.75%, due 2012 $60.0 June 2002 and 2007
6.75%, due 2012 $25.0 June 2004 and 2007
6.73%, due 2012 $25.0 June 2004 and 2007
BGE Obligated Mandatorily Redeemable Trust Preferred Securities
- ---------------------------------------------------------------
On June 15, 1998, BGE Capital Trust I (Trust), a Delaware business trust
established by BGE, issued 10,000,000 Trust Originated Preferred Securities
(TOPrS) for $250 million ($25 liquidation amount per preferred security) with a
distribution rate of 7.16%.
The Trust used the net proceeds from the issuance of the common securities
and the preferred securities to purchase a series of 7.16% Deferrable Interest
Subordinated Debentures due June 30, 2038 (debentures) from BGE in the aggregate
principal amount of $257.7 million with the same terms as the TOPrS. The Trust
must redeem the TOPrS at $25 per preferred security plus accrued but unpaid
distributions when the debentures are paid at maturity or upon any earlier
redemption. BGE has the option to redeem the debentures at any time on or after
June 15, 2003 or at any time when certain tax or other events occur.
The interest paid on the debentures, which the Trust will use to make
distributions on the TOPrS, is included in "Interest expense" in the
Consolidated Statements of Income and is deductible for income tax purposes.
BGE fully and unconditionally guarantees the TOPrS based on its various
obligations relating to the trust agreement, indentures, debentures, and the
preferred security guarantee agreement.
The debentures are the only assets of the Trust. The Trust is wholly owned
by BGE because it owns all the common securities of the Trust that have general
voting power.
For the payment of dividends and in the event of liquidation of BGE, the
debentures are ranked prior to preference stock and common stock.
Other Nonregulated Businesses
- -----------------------------
Revolving Credit Agreement
- --------------------------
ComfortLink has a $50 million unsecured revolving credit agreement that matures
September 26, 2002. Under the terms of the agreement, ComfortLink has the option
to obtain loans at various rates for terms up to nine months. ComfortLink pays a
facility fee on the total amount of the commitment. Under this agreement,
ComfortLink had outstanding $46.0 million at December 31, 2001 and $34.0 million
at December 31, 2000.
On December 18, 2001, ComfortLink entered into a $25.0 million loan
agreement with the Maryland Energy Financing Administration (MEFA). The terms of
the loan exactly match the terms of variable rate, tax exempt bonds due December
1, 2031 issued by MEFA for ComfortLink to finance the cost of building a chilled
water distribution system. The interest rate on this debt resets weekly. These
bonds, and the corresponding loan, can be redeemed at any time at par plus
accrued interest while under variable rates. The bonds can also be converted to
a fixed rate at ComfortLink's option.
Mortgage and Construction Loans
- -------------------------------
Our nonregulated businesses' mortgage and construction loans have varying terms.
The following mortgage notes require monthly principal and interest payments:
o 4.25%, due in 2009
o 9.65%, due in 2028
o 8.00%, due in 2033
The variable rate mortgage notes and construction loans require periodic
payment of principal and interest.
30
Maturities of Long-Term Debt
- ----------------------------
All of our long-term borrowings mature on the following schedule (includes
sinking fund requirements):
Constellation Nonregulated
Year Energy Business BGE
- ----------------------- -------------- ------------- ----------
(In millions)
2002 $635.0 $ 85.4 $ 519.8
2003 -- 86.1 285.6
2004 -- 83.7 155.4
2005 300.0 78.4 46.9
2006 -- 78.4 464.9
Thereafter -- 357.1 947.7
- ----------------------- -------------- ------------- ----------
Total long-term debt
at December 31, 2001 $935.0 $769.1 $2,420.3
======================= ============== ============= ==========
At December 31, 2001, BGE had long-term loans totaling $221.5 million that
mature after 2002 (including $110.0 million of medium-term notes discussed in
this Note under "BGE's Other Long-Term Debt") which contain certain put options
under which lenders could potentially require us to repay the debt prior to
maturity. Of this amount, $171.5 million could be repaid in 2002 and $50.0
million in 2004. At December 31, 2001, $146.5 million is classified as current
portion of long-term debt as a result of these provisions.
At December 31, 2001, our other nonregulated businesses had long-term loans
totaling $20.0 million that mature after 2003 that lenders could potentially
require us to repay early. This amount is classified as current portion of
long-term debt as a result of these repayment provisions.
Weighted-Average Interest Rates for Variable Rate Debt
- ------------------------------------------------------
Our weighted-average interest rates for variable rate debt were:
Year ended December 31, 2001 2000
- ------------------------------------------ -------- --------
Nonregulated Businesses
- -----------------------
(including Constellation Energy)
--------------------------------
Floating rate notes 4.95% 6.98%
Loans under credit agreements 4.60 6.64
Mortgage and construction loans 4.39 7.78
Tax-exempt debt transferred from BGE 3.12 4.26
Other tax-exempt debt 1.75 --
BGE
- ---
Remarketed floating rate series
mortgage bonds 4.49% 6.59%
Floating rate reset notes 4.14 7.27
Medium-term notes, Series G -- 6.58
Medium-term notes, Series H -- 6.58
Note 10. Leases
- --------------------------------------------------------------------------------
There are two types of leases--operating and capital. Capital leases qualify as
sales or purchases of property and are reported in the Consolidated Balance
Sheets. Capital leases are not material in amount. All other leases are
operating leases and are reported in the Consolidated Statements of Income. We
expense all lease payments associated with our regulated utility operations. We
present information about our operating leases below.
Outgoing Lease Payments
- -----------------------
We, as lessee, lease some facilities and equipment. The lease agreements expire
on various dates and have various renewal options.
Lease expense was:
o $11.7 million in 2001,
o $11.3 million in 2000, and
o $12.2 million in 1999.
At December 31, 2001, we owed future minimum payments for long-term,
noncancelable, operating leases as follows:
Year
- ------------------------------------------------ -------------
(In millions)
2002 $ 9.1
2003 24.1
2004 39.2
2005 37.9
2006 13.3
Thereafter 145.8
- ------------------------------------------------ -------------
Total future minimum lease payments $269.4
================================================ =============
The above table includes the operating lease payments for the High Desert
project in California through 2006. We are currently leasing and supervising the
construction of the High Desert project, a 750 megawatt generating facility in
California. The High Desert project uses an off-balance sheet financing
structure through a special-purpose entity (SPE) that qualifies as an operating
lease. The project is scheduled for completion in the summer of 2003.
Under the terms of the lease, we are required to make payments that
represent all or a portion of the lease balance if one of the following events
occurs: termination of construction prior to completion or our default under the
lease.
In addition, we may be required to either post cash collateral equal to the
outstanding lease balance or we may elect to purchase the property for the
outstanding lease balance. At any time during the term of the lease we have the
right to pay off the lease and acquire the asset from the lessor. At December
31, 2001, the outstanding lease balance plus other committed expenses was
$271.2 million.
At the conclusion of the lease term in 2006, we have the following options:
o renew the lease upon approval of the lessors,
o elect to purchase the property for a price equal to the lease balance
at the end of the term, or
o request the lessor to sell the property.
If we request the lessor to sell the property, we guarantee the sale
proceeds up to approximately 83% of the lease balance. The lease balance at the
end of the term is currently estimated to be $600 million, which represents the
estimated cost of the project; however, this may vary based on the ultimate cost
of construction and interest incurred during the construction period.
31
Note 11. Commitments, Guarantees, and Contingencies
- --------------------------------------------------------------------------------
Commitments
- -----------
We have made substantial commitments in connection with our merchant energy,
regulated gas, and other nonregulated business. These commitments relate to:
o purchase of electric generating capacity and energy,
o procurement and delivery of fuels, and
o capital for construction programs and loans.
Our merchant energy business has a long-term contract for the purchase of
electric generating capacity and energy that expires in 2013. Portions of this
contract became uneconomical upon the deregulation of electric generation.
Therefore, we recorded a charge and accrued a corresponding liability based on
the net present value of the excess of estimated contract costs over the
market-based revenues to recover these costs over the remaining term of the
contract as discussed in Note 5 on page 24. At December 31, 2001, the accrued
portion of this contract was $10.6 million.
Our merchant energy business enters into various long-term contracts for the
procurement and delivery of fuels to supply our generating plant requirements.
In most cases, our contracts contain provisions for price escalations, minimum
purchase levels, and other financial commitments. These contracts expire in
various years between 2002 and 2006. In addition, our merchant energy business
enters into long-term contracts for the capacity and transmission rights for the
delivery of energy to meet our physical obligations to our customers. These
contracts expire in various years between 2002 and 2021.
Our merchant energy business also has committed to contribute additional
capital for our construction program and to make additional loans to some
affiliates, joint ventures, and partnerships in which they have an interest.
At December 31, 2001, we estimate the future obligations of our merchant
energy business in the following table:
2002 2003 2004 2005 2006 Thereafter Total
------------------------- ----------- ---------- ---------- ---------- ---------- ------------- -----------
(In millions)
Purchased capacity
and energy $ 16.4 $ 16.0 $ 15.5 $15.1 $15.0 $ 98.5 $ 176.5
Fuel and transportation 318.1 228.3 99.5 49.1 48.8 17.7 761.5
Capital and loans 81.5 0.8 -- -- -- -- 82.3
------------------------- ----------- ---------- ---------- ---------- ---------- ------------- -----------
Total future
obligations $416.0 $245.1 $115.0 $64.2 $63.8 $116.2 $1,020.3
========================= =========== ========== ========== ========== ========== ============= ===========
Our regulated gas business enters into various long-term contracts for the
procurement, transportation, and storage of gas. These contracts are recoverable
under BGE's gas cost adjustment clause discussed in Note 1 on page 12.
BGE Home Products & Services has gas purchase commitments of $35.0 million
in 2002 and $2.2 million in 2003 related to its gas program.
Sale of Receivables
- -------------------
BGE and BGE Home Products & Services have agreements to sell on an ongoing basis
an undivided interest in a designated pool of customer receivables. Under the
agreements, BGE can sell up to a total of $25 million, and BGE Home Products &
Services can sell up to a total of $50 million. Under the terms of the
agreements, the buyer of the receivables has limited recourse against these
entities. BGE and BGE Home Products & Services have recorded reserves for credit
losses. At December 31, 2001, BGE had sold $8.1 million and BGE Home Products &
Services had sold $42.5 million of receivables under these agreements.
Guarantees
- ----------
At December 31, 2001, Constellation Energy issued guarantees in an amount up to
$1,682.4 million related to credit facilities and contractual performance of
certain of its nonregulated subsidiaries, including $600 million relating to the
High Desert project. The actual subsidiary liabilities related to these
guarantees totaled $369.9 million at December 31, 2001.
At December 31, 2001, Constellation Nuclear guaranteed the $388.1 million
sellers' note that financed the acquisition of Nine Mile Point. This guarantee
contains covenant provisions that require Constellation Nuclear to maintain a
net worth of at least $500 million and a ratio of current assets to current
liabilities of at least 1.1.
At December 31, 2001, our merchant energy business had other guaranteed
outstanding loans and letters of credit of certain power projects totaling $26.7
million.
At December 31, 2001, our other nonregulated businesses had guaranteed
outstanding loans and letters of credit of real estate projects totaling $15.9
million.
BGE guarantees two-thirds of certain debt of Safe Harbor Water Power
Corporation. At December 31, 2001, Safe Harbor Water Power Corporation had
outstanding debt of $20 million. The maximum amount of BGE's guarantee is $13.3
million. Additionally at December 31, 2001, BGE guaranteed the TOPrS of $250.0
million as discussed in Note 9 on page 30.
We assess the risk of loss from these guarantees to be minimal.
32
Environmental Matters
- ---------------------
We are subject to regulation by various federal, state and local authorities
with regard to:
o air quality,
o water quality,
o chemical and waste management and disposal, and
o other environmental matters.
The development (involving site selection, environmental assessments, and
permitting), construction, acquisition, and operation of electric generating,
transmission, and distribution facilities are subject to extensive federal,
state, and local environmental and land use laws and regulations. From the
beginning phases of siting and developing, to the ongoing operation of existing
or new electric generating, transmission, and distribution facilities, our
activities involve compliance with diverse laws and regulations that address
emissions and impacts to air and water, special, protected, and cultural
resources (such as wetlands, endangered species, and archeological/historical
resources), chemical and waste handling, and noise impacts. Our activities
require complex and often lengthy processes to obtain approvals, permits, or
licenses for new, existing, or modified facilities. Additionally, the use and
handling of various chemicals or hazardous materials (including wastes) requires
preparation of release prevention plans and emergency response procedures. As
new laws or regulations are promulgated, we assess their applicability and
implement the necessary modifications to our facilities or their operation, as
required.
We discuss the significant matters below.
Clean Air Act
- -------------
The Clean Air Act affects both existing generating facilities and new projects.
The Clean Air Act and many state laws require significant reductions in SO2
(sulfur dioxide) and NOx (nitrogen oxide) emissions that result from burning
fossil fuels. The Clean Air Act also contains other provisions that could
materially affect some of our projects. Various provisions may require permits,
inspections, or installation of additional pollution control technology. Certain
of these provisions are described in more detail below. Since our generation
portfolio is diverse, both in the mix of fuels used to generate electricity, as
well as in the age of various facilities, the Clean Air Act requirements have
different impacts in terms of compliance costs for each of our projects. Many of
these compliance costs may be substantial, as described in more detail below. In
addition, the Clean Air Act contains many enforcement tools, ranging from broad
investigatory powers to civil, criminal, and administrative penalties and
citizen suits. These enforcement provisions also include enhanced monitoring,
recordkeeping, and reporting requirements for both existing and new facilities.
The Clean Air Act creates a marketable commodity called an SO2 "allowance."
All non-exempt facilities over 25 megawatts that emit SO2 must obtain allowances
in order to operate after 1999. Each allowance gives the owner the right to emit
one ton of SO2. All non-exempt existing facilities have been allocated
allowances based on a facility's past production and the statutory emission
reduction goals. If additional allowances are needed for new facilities, they
can be purchased from facilities having excess allowances or from S02 allowance
banks. Our projects comply with the S02 allowance caps through the purchase of
allowances, use of emission control devices, or by qualifying for exemptions. We
believe that the additional costs of obtaining allowances needed for future
generation projects should not materially affect our ability to build, acquire,
and operate them.
The Clean Air Act also requires states to impose annual operating permit
fees. These fees are based on the tons of pollutants emitted from a generating
facility and vary based on the type of facility. For example, fees will
typically be greater for coal-fired plants than for natural gas fired plants.
Our portfolio includes coal-fired plants and gas fired plants, as well as plants
using renewable energy sources such as solar and geothermal, which have far less
emissions. The fees do not significantly increase our costs.
The Ozone Transport Assessment Group, composed of state and local air
regulatory officials from the 37 Mid-Western and Eastern states, has recommended
additional NOx emission reductions that go beyond current federal standards.
These recommendations include reductions from utility and industrial boilers
during the summer ozone season.
As a result of the Ozone Transport Assessment Group's recommendations, on
October 27, 1998, the Environmental Protection Agency (EPA) issued a rule
requiring 22 Eastern states and the District of Columbia to reduce emissions of
NOx ( a precursor of ozone). Among other things, the EPA's rule establishes an
ozone season, which runs from May through September, and a NOx emission budget
for each state, including Maryland and Pennsylvania. The EPA rule requires
states to implement controls sufficient to meet their NOx budget by May 30,
2004. Coal-fired power plants are a principal target of NOx reductions under
this initiative, however, some of our newer coal fired plants may already meet
the EPA expectations and will not require the same amount of capital
expenditures.
Many of the generation facilities are subject to NOx reduction requirements
under the EPA rule including those located in Maryland and Pennsylvania. This
regulation affects both new and existing facilities causing additional capital
investment. At the Brandon Shores facility we have installed, and at our Wagner
facility we are installing emission reduction equipment by May 2002, in order to
meet Maryland regulations issued pursuant to EPA's rule. The owners of the
Keystone plant in Pennsylvania are installing emissions reduction equipment by
2003 to meet Pennsylvania regulations issued pursuant to EPA's rule. We estimate
that the equipment needed at these plants will cost approximately $290 million.
Through December 31, 2001, we have spent approximately $200 million.
33
Over the past two years, the EPA and several states have filed suits against
a number of coal-fired power plants in Mid-Western and Southern states alleging
violations of the deterioration prevention and non-attainment provisions of the
Clean Air Act's new source review requirements. In 2000, using its broad
investigatory powers, the EPA requested information relating to modifications
made to our Brandon Shores, Crane, and Wagner plants in Baltimore, Maryland. The
EPA also sent similar, but narrower, information requests to two of our newer
Pennsylvania waste-coal burning plants. We have responded to the EPA and are
waiting to see if the EPA takes any further action. This information is to
determine compliance with the Clean Air Act and state implementation plan
requirements, including potential application of federal New Source Performance
Standards.
In general, such standards can require the installation of additional air
pollution control equipment upon the major modification of an existing plant.
Although there have not been any new source review-related suits filed against
our facilities, there can be no assurance that any of them will not be the
target of an action in the future. Based on the levels of emissions control that
the EPA and/or states are seeking in these new source review enforcement
actions, we believe that material additional costs and penalties could be
incurred, and/or planned capital expenditures could be accelerated, if the EPA
was successful in any future actions regarding our facilities.
The Clean Air Act requires the EPA to evaluate the public health impacts of
emissions of mercury, a hazardous air pollutant, from coal-fired plants. The EPA
has decided to control mercury emissions from coal-fired plants. Compliance
could be required by approximately 2007. Final regulations are expected to be
issued in 2004 and would affect all coal-fired boilers. The cost of compliance
could be material.
Future initiatives regarding greenhouse gas emissions and global warming
continue to be the subject of much debate. The related Kyoto Protocol was signed
by the United States but has not yet been ratified by the U.S. Senate. Future
initiatives on this issue and the ultimate effects of the Kyoto Protocol on us
are unknown at this time. As a result of our diverse fuel portfolio, our
contribution to greenhouse gases varies. Fossil fuel-fired power plants,
however, are significant sources of carbon dioxide emissions, a principal
greenhouse gas. Therefore, our compliance costs with any mandated federal
greenhouse gas reductions in the future could be significant.
Waste Disposal
- --------------
The EPA and several state agencies have notified us that we are considered a
potentially responsible party with respect to the cleanup of certain
environmentally contaminated sites owned and operated by others. We cannot
estimate the cleanup costs for all of these sites.
We can, however, estimate that our current 15.47% share of the reasonably
possible cleanup costs at one of these sites, Metal Bank of America, a metal
reclaimer in Philadelphia, could be as much as $2.3 million higher than amounts
we have recorded as a liability on our Consolidated Balance Sheets. This
estimate is based on a Record of Decision issued by the EPA.
Also, we are coordinating investigation of several sites where gas was
manufactured in the past. The investigation of these sites includes reviewing
possible actions to remove coal tar. In late December 1996, we signed a consent
order with the Maryland Department of the Environment (MDE) that required us to
implement remedial action plans for contamination at and around the Spring
Gardens site, located in Baltimore, Maryland. We submitted the required remedial
action plans and they were approved by the MDE. Based on the remedial action
plans, the costs we consider to be probable to remedy the contamination are
estimated to total $47 million. We have recorded these costs as a liability on
our Consolidated Balance Sheets and have deferred these costs, net of
accumulated amortization and amounts we recovered from insurance companies, as a
regulatory asset. Because of the results of studies at these sites, it is
reasonably possible that these additional costs could exceed the amount we
recognized by approximately $14 million. We discuss this further in Note 6 on
page 25. Through December 31, 2001, we have spent approximately $37 million for
remediation at this site.
We do not expect the cleanup costs of the remaining sites to have a material
effect on our financial results.
Litigation
- ----------
In the normal course of business, we are involved in various legal proceedings.
We discuss the significant matters below.
California
- ----------
Baldwin Associates, Inc. v. Gray Davis, Governor of California and 22 other
defendants (including Constellation Power Development, Inc., a subsidiary of
Constellation Power, Inc.) - This class action lawsuit was filed on October 5,
2001 in the Superior Court, County of San Francisco. The action seeks damages of
$43 billion, recession and reformation of approximately 38 long-term power
purchase contracts, and an injunction against improper spending by the state of
California. Constellation Power Development, Inc. is named as a defendant but
does not have a power purchase agreement with the State of California. However,
our High Desert Power Project does have a power purchase agreement with the
California Department of Water Resources. We believe this case is without merit.
However, we cannot predict the timing, or outcome, of it or its possible effect
on our financial results.
34
Employment Discrimination
- -------------------------
Miller, et. al v. Baltimore Gas and Electric Company, et al.--This action was
filed on September 20, 2000 in the U.S. District Court for the District of
Maryland. Besides BGE, Constellation Energy Group, Constellation Nuclear and
Calvert Cliffs Nuclear Power Plant are also named defendants. The action seeks
class certification for approximately 150 past and present employees and alleges
racial discrimination at Calvert Cliffs Nuclear Power Plant. The amount of
damages is unspecified, however the plaintiffs seek back and front pay, along
with compensatory and punitive damages. The Court scheduled a briefing process
for the motion to certify the case as a class action suit for the beginning of
2003. We believe this case is without merit. However, we cannot predict the
timing, or outcome, of it or its possible effect on our, or BGE's, financial
results.
Asbestos
- --------
Since 1993, BGE has been involved in several actions concerning asbestos. 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 is direct claims by individuals exposed to asbestos. BGE is
involved in these claims with approximately 70 other defendants. Approximately
545 individuals that were never employees of BGE each claim $6 million in
damages ($2 million compensatory and $4 million punitive). These claims were
filed in the Circuit Court for Baltimore City, Maryland in the summer of 1993.
BGE does not know the specific facts necessary to estimate its potential
liability for these claims. The specific facts BGE does not know include:
o the identity of BGE's facilities at which the plaintiffs allegedly
worked as contractors,
o the names of the plaintiff's employers, and
o the date on which the exposure allegedly occurred.
To date, 36 of these cases were settled for amounts that were not
significant.
The second type is claims by one manufacturer--Pittsburgh Corning Corp.
(PCC)--against BGE and approximately eight others, as third-party defendants. On
April 17, 2000, PCC declared bankruptcy, and BGE does not expect PCC to
prosecute these claims.
These claims relate to approximately 1,500 individual plaintiffs and were
filed in the Circuit Court for Baltimore City, Maryland in the fall of 1993. To
date, about 375 cases have been resolved, all without any payment by BGE. BGE
does not know the specific facts necessary to estimate its potential liability
for these claims. The specific facts we do not know include:
o the identity of BGE facilities containing asbestos manufactured by the
manufacturer,
o the relationship (if any) of each of the individual plaintiffs to BGE,
o the settlement amounts for any individual plaintiffs who are shown to
have had a relationship to BGE, and
o the dates on which/places at which the exposure allegedly occurred.
Until the relevant facts for both types of 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 awards in the actions, its potential liability could be
material.
Asset Transfer Order
- --------------------
On July 6, 2000, the Mid-Atlantic Power Supply Association (MAPSA) and Shell
Energy LLC filed, in the Circuit Court for Baltimore City, a petition for review
and a delay of the Maryland PSC's order approving the transfer of BGE's
generation assets issued on June 19, 2000. The Court denied MAPSA's request for
a delay on August 4, 2000, and after a hearing on the petition on August 23,
2000 issued an order on September 29, 2000 upholding the Maryland PSC's order on
the asset transfer. On October 27, 2000, MAPSA filed an appeal with the Maryland
Court of Special Appeals challenging the September 29, 2000 order issued by the
Circuit Court. The Court of Special Appeals heard oral arguments on the appeal
on September 7, 2001. We also believe that this petition is without merit.
However, we cannot predict the timing or outcome of this case, which could have
a material adverse effect on our, and BGE's, financial results.
Restructuring Order
- -------------------
In early December 1999, MAPSA, Trigen-Baltimore Energy Corporation and
Sweetheart Cup Company, Inc. filed appeals of the Restructuring Order, which
were consolidated in the Baltimore City Circuit Court. MAPSA also filed a motion
to delay implementation of the Restructuring Order, pending a decision on the
merits of the appeals by the court.
On April 21, 2000, the Circuit Court dismissed MAPSA's appeal based on a
lack of standing (the right of a party to bring a lawsuit to court) and denied
its motion for a delay of the Restructuring Order. However, MAPSA filed an
appeal of this decision. On May 24, 2000, the Circuit Court dismissed both the
Trigen and Sweetheart Cup appeals.
MAPSA subsequently filed several appeals with the Maryland Court of Special
Appeals, the Maryland Court of Appeals, and the Baltimore City Circuit Court.
The effect of the appeals was to delay the implementation of customer choice in
BGE's service territory.
However, on August 4, 2000, the delay was rescinded and BGE retroactively
adjusted its rates as if customer choice had been implemented July 1, 2000.
On September 29, 2000, the Baltimore City Circuit Court issued an order
upholding the Restructuring Order.
On October 27, 2000, MAPSA filed an appeal with the Maryland Court of
Special Appeals challenging the September 29, 2000 order issued by the Circuit
Court. The Court of Special Appeals heard oral arguments on the appeal on
September 7, 2001. We believe that this petition is without merit. However, we
cannot predict the timing or outcome of this case, which could have a material
adverse effect on our, and BGE's, financial results.
35
Nuclear Insurance
- -----------------
We maintain nuclear insurance coverage for Calvert Cliffs and Nine Mile Point in
four program areas: liability, worker radiation claims, property, and accidental
outage. However, these policies have certain industry standard exclusions, such
as ordinary wear and tear, and war. Terrorist acts, while not excluded from the
property and accidental outage policies, are covered as a common occurrence,
meaning that if terrorist acts occur against one or more commercial nuclear
power plants insured by our insurance company within a 12 month period, they
will be treated as one event and the owners of the plants will share one full
limit of each type of policy (currently $3.24 billion). Claims that arise out of
terrorist acts are also covered by our nuclear liability and worker radiation
policies. However, these policies are subject to one industry aggregate limit
(currently $200 million) for the risk of terrorism. Unlike the property and
accidental outage policies, however, an industry-wide retrospective assessment
program applies above the industry limit (see below for explanation of this
program).
If there were an accident or an extended outage at any unit of Calvert
Cliffs or Nine Mile Point, it could have a substantial adverse financial effect
on us.
Liability Insurance
- -------------------
Pursuant to the Price-Anderson Act, we are required to insure against public
liability claims resulting from nuclear incidents to the full limit of
approximately $9.5 billion. We have purchased the maximum available commercial
insurance of $200 million, and the remaining $9.3 billion is provided through
mandatory participation in an industry-wide retrospective assessment program.
Under this retrospective assessment program, we can be assessed up to $352.4
million per incident, payable at no more than $40 million per incident per year.
This assessment also applies in excess of our worker radiation claims insurance
and is subject to inflation and state premium taxes. In addition, the U.S.
Congress could impose additional revenue-raising measures to pay claims.
Some of the provisions of this Act expire in August 2002, and the Act is
subject to change if those provisions are extended. While we expect these
provisions to be extended, we do not know what impact any changes to the Act may
have on us.
Worker Radiation Claims Insurance
- ---------------------------------
We participate in the American Nuclear Insurers Master Worker Program that
provides coverage for worker tort claims filed for radiation injuries. Effective
January 1, 1998, this program was modified to provide coverage to all workers
whose nuclear-related employment began on or after the commencement date of
reactor operations. Waiving the right to make additional claims under the old
policy was a condition for acceptance under the new policy. We describe the old
and new policies below:
o Nuclear worker claims reported on or after January 1, 1998 are covered
by a new insurance policy with an annual industry aggregate limit of $200
million for radiation injury claims against all those insured by this
policy.
o All nuclear worker claims reported prior to January 1, 1998 are still
covered by the old policy. Insureds under the old policies, with no
current operations, are not required to purchase the new policy described
above, and may still make claims against the old policies through 2007.
If radiation injury claims under these old policies exceed the policy
reserves, all policyholders could be retroactively assessed, with our
share being up to $6.3 million.
The sellers of Nine Mile Point retain the liabilities for existing and
potential claims that occurred prior to November 7, 2001. In addition, the Long
Island Power Authority, which continues to own 18 percent of Unit 2 at Nine Mile
Point, is obligated to assume its pro rata share of any liabilities for
retrospective premiums and other premiums assessments. If claims under these
polices exceed the coverage limits, the provisions of the Price-Anderson Act
would apply.
Property Insurance
- ------------------
Our policies provide $500 million in primary and an additional $2.25 billion in
excess coverage for property damage, decontamination, and premature
decommissioning liability for Calvert Cliffs or Nine Mile Point. If accidents at
any insured plants cause a shortfall of funds at the industry mutual insurance
company, all policyholders could be assessed, with our share being up to $56.2
million.
Accidental Outage Insurance
- ---------------------------
Our policies provide indemnification on a weekly basis resulting from an
accidental outage of a nuclear unit. Initial coverage begins after a 12-week
deductible period and continues at 100% of the weekly indemnity limit for 52
weeks and 80% of the weekly indemnity limit for the next 110 weeks. Our coverage
is up to $490.0 million per unit at Calvert Cliffs, $335.4 million for Unit 1 of
Nine Mile Point, and $412.6 million for Unit 2 of Nine Mile Point. This amount
can be reduced by up to $98.0 million per unit at Calvert Cliffs and $82.5
million for Nine Mile Point if an outage at either plant is caused by a single
insured physical damage loss.
California Power Purchase Agreements
- ------------------------------------
Our merchant energy business has $296.4 million invested in operating power
projects of which our ownership percentage represents 142 megawatts of
electricity that are sold to Pacific Gas & Electric (PGE) and to Southern
California Edison (SCE) in California under power purchase agreements. Our
merchant energy business was not paid in full for its sales from these plants to
the two utilities from November 2000 through early April 2001. At December 31,
2001, our portion of the amount due for unpaid power sales from these utilities
was approximately $45 million. We recorded reserves of approximately 20% of this
amount.
36
These projects entered into agreements with PGE and SCE that provide for
five-year fixed-price payments averaging $53.70 per megawatt-hour plus the
stated capacity payments in the original Interim Standard Offer No. 4 (SO4)
contracts. These agreements also provide for the payment of all past due amounts
plus interest, which the projects expect to collect within the next two years.
The SCE agreement to pay these past due amounts is contingent on SCE making
certain payments to other creditors.
As a result of ongoing litigation before the FERC regarding sales into the
spot markets of the California Independent System Operator and Power Exchange,
we may be required to pay refunds of between $3 and $4 million for transactions
that we entered into with these entities for the period between October 2000 and
June 2001. While the process at FERC is ongoing, FERC has indicated that we will
have the ability to reduce the potential refund amount in order to recover
outstanding receivables we are owed. FERC also has indicated that it will
consider adjustments to the refund amount to the extent we can demonstrate that
its refund methodology resulted in an overall revenue shortfall for our
transactions in these markets during the refund period.
Note 12. Risk Management Activities and Fair Value of Financial Instruments
- --------------------------------------------------------------------------------
Risk Management Activities
- --------------------------
In 2001, we entered into forward starting interest rate swap contracts to manage
a portion of our interest rate exposure for anticipated long-term borrowings to
refinance our outstanding commercial paper obligations and maturing long-term
debt. The swaps have notional or contract amounts that total $800 million with
an average rate of 4.9% and expire in the first quarter of 2002. The notional
amounts of the contracts do not represent amounts that are exchanged by the
parties and are not a measure of our exposure to market or credit risks. The
notional amounts are used in the determination of the cash settlements under the
contracts. At December 31, 2001, the fair value of these swaps was an unrealized
pre-tax gain of $36.3 million.
At December 31, 2001, these swaps were designated as cash-flow hedges under
SFAS No. 133. We recorded this unrealized gain in "Other current assets" in our
Consolidated Balance Sheets and "Accumulated other comprehensive income," net of
associated deferred income tax effects, in our Consolidated Statements of Common
Shareholders' Equity and Consolidated Statements of Capitalization. Any gain or
loss on the hedges will be reclassified from "Accumulated other comprehensive
income" into "Interest expense" and be included in earnings during the periods
in which the interest payments being hedged occur.
In 2002, we entered into additional forward starting interest rate swaps
with notional amounts that total $700 million. These swaps have an average rate
of 5.9% and expire in the first quarter of 2002.
Our power marketing operation manages the commodity price risk of our
electric generation operations as part of its overall portfolio. In order to
manage this risk, our merchant energy business may enter into fixed-price
derivative or non-derivative contracts to hedge the variability in future cash
flows from forecasted sales of electricity and purchases of fuel as discussed in
Note 1 on page 13.
At December 31, 2001, our merchant energy business had designated certain
fixed-price forward electricity sale contracts as cash-flow hedges of forecasted
sales of electricity for the years 2002 through 2010 under SFAS No. 133.
At December 31, 2001, our merchant energy business recorded net unrealized
pre-tax gains of $76.5 million on these hedges, net of associated deferred
income tax effects, in "Accumulated other comprehensive income". We expect to
reclassify $5.7 million of net pre-tax gains on cash flow hedges from
"Accumulated other comprehensive income" into earnings during the next twelve
months based on the market prices at December 31, 2001. However, the actual
amount reclassified into earnings could vary from the amounts recorded at
December 31, 2001 due to future changes in market prices. In 2001, there was no
hedge ineffectiveness recognized in earnings.
At December 31, 2000, our merchant energy business recorded deferred pre-tax
hedge losses of $58.3 million in "Other deferred charges" in our Consolidated
Balance Sheets for the fixed-price forward electricity sale contracts designated
as a hedge of forecasted sales of electricity. We reclassified these deferred
hedge losses, net of associated deferred income tax effects, to "Accumulated
other comprehensive income" upon the adoption of SFAS No. 133, in the first
quarter of 2001.
Fair Value of Financial Instruments
- -----------------------------------
The fair value of a financial instrument represents the amount at which the
instrument could be exchanged in a current transaction between willing parties,
other than in a forced sale or liquidation. Significant differences can occur
between the fair value and carrying amount of financial instruments that are
recorded at historical amounts. We use the following methods and assumptions for
estimating fair value disclosures for financial instruments:
o cash and cash equivalents, net accounts receivable, other current
assets, certain current liabilities, short-term borrowings, current
portion of long-term debt, and certain deferred credits and other
liabilities: because of their short-term nature, the amounts reported in
our Consolidated Balance Sheets approximate fair value,
o investments and other assets where it was practicable to estimate fair
value: the fair value is based on quoted market prices where available,
and
o for long-term debt: the fair value is based on quoted market prices where
available or by discounting remaining cash flows at current market rates.
37
We show the carrying amounts and fair values of financial instruments
included in our Consolidated Balance Sheets in the following table, and we
describe some of the items separately later in this section.
At December 31, 2001 2000
- ------------------------- ------------------- ------------------
Carrying Fair Carrying Fair
Amount Value Amount Value
- ------------------------- --------- --------- -------- ---------
(In millions)
Investments and other assets
for which it is:
Practicable to
estimate fair value $1,144.9 $1,144.9 $ 349.8 $ 349.8
Not practicable to
estimate fair value 25.8 N/A 32.7 N/A
Fixed-rate long-term
debt 2,945.3 3,069.6 2,734.1 2,819.9
Variable-rate long-term
debt 1,179.1 1,179.1 1,331.8 1,331.8
It was not practicable to estimate the fair value of investments held by our
nonregulated businesses in several financial partnerships that invest in
nonpublic debt and equity securities. This is because the timing and amount of
cash flows from these investments are difficult to predict. We report these
investments at their original cost in our Consolidated Balance Sheets.
The investments in financial partnerships totaled $25.8 million at December
31, 2001 and $32.7 million at December 31, 2000, representing ownership
interests up to 11%. The total assets of all of these partnerships totaled $5.4
billion at December 31, 2000 (which is the latest information available).
Guarantees
- ----------
It was not practicable to determine the fair value of certain loan guarantees of
Constellation Energy and its subsidiaries. Constellation Energy guaranteed
outstanding debt of $47.9 million at December 31, 2001 and $341.0 million at
December 31, 2000.
Our merchant energy business guaranteed outstanding debt totaling $414.8
million at December 31, 2001 and $33.6 million at December 31, 2000.
Our other nonregulated businesses guaranteed outstanding debt totaling $15.9
million at December 31, 2001 and $16.5 million at December 31, 2000.
BGE guaranteed outstanding debt of $263.3 million at December 31, 2001 and
2000.
We do not anticipate that we will need to fund these guarantees.
38
Note 13. Stock-Based Compensation
- --------------------------------------------------------------------------------
As permitted by SFAS No. 123, Accounting for Stock-Based Compensation, we
measure our stock-based compensation in accordance with Accounting Principles
Board Opinion (APB) No. 25, Accounting for Stock Issued to Employees, and
related interpretations.
Under our existing long-term incentive plans, we can issue awards that
include stock options and performance-based restricted stock to officers and key
employees. Under the plans, we can issue up to a total of 6,000,000 shares for
these awards.
Stock Options
- -------------
In May 2000, our Board of Directors approved the issuance of nonqualified stock
options. Options have been granted at prices not less than the market value of
the stock at the date of grant, generally become exercisable ratably over a
three-year period beginning one-year from the date of grant, and expire ten
years from the date of grant. In accordance with APB No. 25, no compensation
expense is recognized for the stock option awards. Summarized information for
our stock option awards is as follows:
2001 2000
- ------------------ --------------------- --------------------
Weighted- Weighted-
Average Average
Exercise Exercise
Shares Price Shares Price
- ------------------ ---------- ---------- --------- ----------
(In thousands, except per share amounts)
Outstanding,
beginning of year 2,420 $34.65 -- $ --
Granted 1,015 25.08 2,462 34.64
Exercised (512) (34.25) -- --
Cancelled/
Expired (277) (37.74) (42) (34.25)
- ------------------ --------- ----------- --------- ----------
Outstanding,
end of year 2,646 $30.73 2,420 $34.65
================== ========= =========== ========= ==========
Exercisable,
end of year 235 $34.25 -- --
================== ========= =========== ========= ==========
Weighted-average
fair value per
share of options
granted $9.27 $5.60
================== ========= =========== ========= ==========
The following table summarizes information about stock options outstanding
at December 31, 2001 (shares in thousands):
Weighted-Average
Remaining
Exercise Number Contractual Number
Plan Year Prices Outstanding Life Exercisable
- ---------- ------------ ------------ ---------------- ------------
2001 $25.08 1,015 9.9 --
2000 $34.25 1,631 8.4 235
Performance-Based Restricted Stock Awards
- -----------------------------------------
In addition, we issue common stock based on meeting certain performance and
service goals over a three to five year period. This stock vests to participants
at various times ranging from three to five years or less. In accordance with
APB No. 25, we recognize compensation expense for our restricted stock awards
using the variable accounting method. In 2001, due to non-attainment of
performance criteria, we recorded a credit to compensation expense of $10.1
million. We recorded compensation expense of $16.3 million for 2000 and $10.5
million for 1999. Summarized share information for our restricted stock awards
is as follows:
2001 2000 1999
- ---------------------------------- ------- -------- ---------
(In thousands, except per share amounts)
Outstanding, beginning of year 377 323 350
Granted 87 353 358
Released to participants -- (277) (362)
Cancelled (29) (22) (23)
- ---------------------------------- ------- -------- ---------
Available for grant, end of year 435 377 323
================================== ======= ======== =========
Weighted-average fair value
restricted stock granted $35.24 $32.89 $28.61
================================== ======= ======== =========
Pro-forma Information
- ---------------------
Disclosure of pro-forma information regarding net income and earnings per share
is required under SFAS No. 123, which uses the fair value method. The fair
values of our stock-based awards were estimated as of the date of grant using
the Black-Scholes option pricing model based on the following weighted-average
assumptions:
2001 2000
- --------------------------- ---------- ----------
Risk-free interest rate 4.79% 6.37%
Expected life (in years) 5.0 10.0
Expected market price
volatility factors 41.3% 21.0%
Expected dividend yields 1.8% 5.7%
Had compensation cost for these plans been recognized under the fair value
method, net income and basic and diluted earnings per share amounts would have
been as follows:
2001
- --------------------------------- ---------
(In millions, except per share amounts)
Pro-forma net income $87.2
Pro-forma earnings per share:
Basic $ .54
Diluted $ .54
The effect of applying SFAS No. 123 to our stock-based awards results in net
income and earnings per share that are not materially different from amounts
reported for the year ended December 31, 2000.
39
Note 14. Acquisition of Nine Mile Point
- --------------------------------------------------------------------------------
On November 7, 2001, we completed our purchase of Nine Mile Point located in
Scriba, New York. Nine Mile Point consists of two boiling-water reactors. Unit 1
is a 609-megawatt reactor that entered service in 1969. Unit 2 is a
1,148-megawatt reactor that began operation in 1988.
Nine Mile Point Nuclear Station, LLC, a subsidiary of Constellation Nuclear,
purchased 100 percent of Nine Mile Point Unit 1 and 82 percent of Unit 2.
Approximately one-half of the purchase price, or $380 million, in addition to
settlement costs of $2.7 million, was paid at closing and the remainder is being
financed through the sellers in a note to be repaid over five years with an
interest rate of 11.0%. This note may be prepaid at any time without penalty.
The sellers also transferred to us approximately $442 million in decommissioning
funds. As a result of this purchase, we own 1,550 megawatts of Nine Mile Point's
1,757 megawatts of total generating capacity.
Niagara Mohawk Power Corporation was the sole owner of Nine Mile Point Unit
1. The co-owners of Unit 2 who sold their interests are: Niagara Mohawk (41
percent), New York State Electric and Gas (18 percent), Rochester Gas & Electric
Corporation (14 percent) and Central Hudson Gas & Electric Corporation (9
percent). The Long Island Power Authority will continue to own 18 percent of
Unit 2.
We will sell 90 percent of our share of Nine Mile Point's output back to the
sellers at an average price of nearly $35 per megawatt-hour for approximately 10
years under power purchase agreements. The contracts for the output are on a
unit contingent basis (if the output is not available because the plant is not
operating, there is no requirement to provide output from other sources).
Nine Mile Point Net Assets Acquired
- -----------------------------------
At November 7, 2001 (In millions)
- ------------------------------------ --------------------
Current Assets $ 135.4
Nuclear Decommissioning Trust Fund 441.7
Net Property, Plant and Equipment 292.6
Intangible Assets (details
below) 38.7
- ------------------------------------ --------------------
Total Assets Acquired 908.4
Current Liabilities 16.9
Deferred Credits and
Other Liabilities 120.7
- ------------------------------------ --------------------
Net Assets Acquired 770.8
Note to Sellers 388.1
- ------------------------------------ --------------------
Total Cash Paid $ 382.7
==================================== ====================
The intangible assets acquired consist of the following:
Weighted-Average
Description Amount Useful Life
- ------------------------- ------------- ----------------
(In millions) (In years)
Operating procedures
and manuals $ 23.4 10
Permits and licenses 12.9 27
Software 2.4 5
- ------------------------- -------------
Total intangible assets $ 38.7
========================= =============
In 2002, Niagara Mohawk, or its successor, will provide funds equal to the
net pension obligation of Nine Mile Point employees following a more precise
estimate of this obligation.
40
Note 15. Quarterly Financial Data (Unaudited)
- --------------------------------------------------------------------------------
Our quarterly financial information has not been audited but, in management's
opinion, includes all adjustments necessary for a fair presentation. Our
business is seasonal in nature with the peak sales periods generally occurring
during the summer and winter months. Accordingly, comparisons among quarters of
a year may not represent overall trends and changes in operations.
2001 Quarterly Data
- -------------------
Earnings
Applicable Earnings
Income to Per Share
from Common Common
Revenue Operations Stock Stock
- ---------------- -------- ---------- ---------- ---------
(In millions, except per share amounts)
Quarter Ended
March 31 $1,147.1 $235.0 $111.8 $0.74
June 30 843.2 171.0 75.6 0.46
September 30 1,036.1 317.5 163.6 1.00
December 31 901.9 (365.7) (260.1) (1.59)
- --------------- ---------- --------- ---------- ---------
Year Ended
December 31 $3,928.3 $357.8 $ 90.9 $0.57
=============== ========== ========= ========== =========
Our first quarter results include a $8.5 million after-tax gain for the
cumulative effect of adopting SFAS No. 133.
Our fourth quarter results include workforce reduction costs, contract
termination related costs, and impairment losses and other costs totaling
$334.8 million after-tax. For details, refer to Note 2 on page 18.
2000 Quarterly Data
- -------------------
Earnings
Applicable Earnings
Income to Per Share
from Common Common
Revenue Operations Stock Stock
- ---------------- -------- ---------- ---------- ---------
(In millions, except per share amounts)
Quarter Ended
March 31 $994.0 $184.6 $ 72.1 $0.48
June 30 866.6 132.1 39.6 0.26
September 30 968.6 313.4 147.5 0.98
December 31 1,023.3 212.5 86.1 0.57
- --------------- ---------- --------- ---------- ---------
Year Ended
December 31 $3,852.5 $842.6 $345.3 $2.30
=============== ========== ========= ========== =========
Our first quarter results include a $2.5 million after-tax expense for BGE
employees that elected to participate in a targeted VSERP (see Note 2).
Our second quarter results include:
o a $15.0 million after-tax deregulation transition cost to Goldman Sachs
incurred by our power marketing operation to provide BGE's standard offer
service requirements (see Note 3), and
o a $1.7 million after-tax expense for the VSERP (see Note 2).
The sum of the quarterly earnings per share amounts may not equal the total for
the year due to the effects of rounding and dilution as a result of issuing
common shares during the year.
Certain prior-year amounts have been reclassified to conform with the current
year's presentation.
41