UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For The Quarterly Period Ended SEPTEMBER 30, 2001
Commission Exact name of registrant as IRS Employer
File Number specified in its charter Identification No.
----------- ------------------------------------- ------------------
1-12869 CONSTELLATION ENERGY GROUP, INC. 52-1964611
1-1910 BALTIMORE GAS AND ELECTRIC COMPANY 52-0280210
MARYLAND
-----------------------------------
(State of Incorporation)
250 W. PRATT STREET, BALTIMORE, MARYLAND 21201
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(Address of principal executive offices) (Zip Code)
410-234-5000
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(Registrants' telephone number, including area code)
NOT APPLICABLE
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(Former name, former address
and former fiscal year, if changed since last report)
Indicate by check mark whether the registrants (1) have filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months, and (2) have been subject to such filing
requirements for the past 90 days.
Yes X No
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Common Stock, without par value 163,707,950 shares outstanding of Constellation
Energy Group, Inc. on October 31, 2001.
TABLE OF CONTENTS
Page
Part I -- Financial Information
Item 1 -- Financial Statements
Constellation Energy Group, Inc. and Subsidiaries
Consolidated Statements of Income...................................................... 3
Consolidated Statements of Comprehensive Income........................................ 3
Consolidated Balance Sheets............................................................ 4
Consolidated Statements of Cash Flows.................................................. 6
Baltimore Gas and Electric Company and Subsidiaries
Consolidated Statements of Income...................................................... 7
Consolidated Balance Sheets............................................................ 8
Consolidated Statements of Cash Flows.................................................. 10
Notes to Consolidated Financial Statements............................................. 11
Item 2 -- Management's Discussion and Analysis of Financial Condition and
Results of Operations
Introduction........................................................................... 20
Recent Events.......................................................................... 21
Strategy............................................................................... 22
Current Issues......................................................................... 22
Results of Operations.................................................................. 27
Financial Condition.................................................................... 35
Capital Resources...................................................................... 35
Other Matters.......................................................................... 37
Item 3 -- Quantitative and Qualitative Disclosures About Market Risk............................. 38
Part II -- Other Information
Item 1 -- Legal Proceedings...................................................................... 38
Item 5 -- Other Information...................................................................... 40
Item 6 -- Exhibits and Reports on Form 8-K....................................................... 41
Signature........................................................................................ 42
2
CONSTELLATION ENERGY GROUP, INC. AND SUBSIDIARIES
PART 1 - FINANCIAL INFORMATION
Item 1 - Financial Statements
Consolidated Statements of Income (Unaudited)
Three Months Ended Nine Months Ended
September 30, September 30,
2001 2000 2001 2000
- -------------------------------------------------------------------------------------------------------------------
Revenues (In millions, except per share amounts)
Nonregulated revenues $ 335.1 $ 283.7 $ 873.9 $ 768.4
Regulated electric revenues 634.4 598.2 1,624.0 1,688.0
Regulated gas revenues 66.6 86.7 528.5 372.8
- -------------------------------------------------------------------------------------------------------------------
Total revenues 1,036.1 968.6 3,026.4 2,829.2
Expenses
Operating expenses 560.5 497.9 1,824.8 1,666.4
Depreciation and amortization 102.9 107.6 308.5 370.7
Taxes other than income taxes 55.2 49.7 169.6 162.2
- -------------------------------------------------------------------------------------------------------------------
Total expenses 718.6 655.2 2,302.9 2,199.3
- -------------------------------------------------------------------------------------------------------------------
Income from Operations 317.5 313.4 723.5 629.9
Other Income (Expense) 2.3 (0.3) 5.3 5.8
- -------------------------------------------------------------------------------------------------------------------
Income Before Fixed Charges and Income Taxes 319.8 313.1 728.8 635.7
Fixed Charges
Interest expense (net) 54.3 66.6 170.7 192.0
BGE preference stock dividends 3.3 3.3 9.9 9.9
- -------------------------------------------------------------------------------------------------------------------
Total fixed charges 57.6 69.9 180.6 201.9
- -------------------------------------------------------------------------------------------------------------------
Income Before Income Taxes 262.2 243.2 548.2 433.8
Income Taxes
Current 86.5 105.1 198.9 211.9
Deferred 14.2 (7.3) 12.9 (31.0)
Investment tax credit adjustments (2.1) (2.1) (6.1) (6.3)
- -------------------------------------------------------------------------------------------------------------------
Total income taxes 98.6 95.7 205.7 174.6
- -------------------------------------------------------------------------------------------------------------------
Income Before Cumulative Effect of
Change in Accounting Principle 163.6 147.5 342.5 259.2
Cumulative Effect of Change in Accounting Principle,
Net of Income Taxes of $5.6 -- -- 8.5 --
- -------------------------------------------------------------------------------------------------------------------
Net Income $ 163.6 $ 147.5 $ 351.0 $ 259.2
- -------------------------------------------------------------------------------------------------------------------
Earnings Applicable to Common Stock $ 163.6 $ 147.5 $ 351.0 $ 259.2
===================================================================================================================
Average Shares of Common Stock Outstanding 163.7 150.1 159.8 149.8
Earnings Per Common Share and Earnings Per
Common Share - Assuming Dilution Before
Cumulative Effect of Change in Accounting Principle $ 1.00 $ 0.98 $ 2.14 $ 1.73
Cumulative Effect of Change in Accounting Principle -- -- .06 --
- -------------------------------------------------------------------------------------------------------------------
Earnings Per Common Share and
Earnings Per Common Share - Assuming Dilution $ 1.00 $ 0.98 $ 2.20 $ 1.73
Dividends Declared Per Common Share $ 0.12 $ 0.42 $ 0.36 $ 1.26
Consolidated Statements of Comprehensive Income (Unaudited)
Three Months Ended Nine Months Ended
September 30, September 30,
2001 2000 2001 2000
- -------------------------------------------------------------------------------------------------------------------
(In millions)
Net Income $ 163.6 $ 147.5 $ 351.0 $ 259.2
Other comprehensive (loss) income, net of taxes (18.3) 17.7 161.0 41.8
- -------------------------------------------------------------------------------------------------------------------
Comprehensive Income Before Cumulative Effect of
Change in Accounting Principle 145.3 165.2 512.0 301.0
Cumulative Effect of Change in Accounting Principle,
Net of Income Taxes of $22.6 -- -- (35.5) --
- -------------------------------------------------------------------------------------------------------------------
Comprehensive Income $ 145.3 $ 165.2 $ 476.5 $ 301.0
===================================================================================================================
See Notes to Consolidated Financial Statements.
Certain prior-period amounts have been reclassified to conform with the current
period's presentation.
3
CONSTELLATION ENERGY GROUP, INC. AND SUBSIDIARIES
PART 1 - FINANCIAL INFORMATION (CONTINUED)
Item 1 - Financial Statements
Consolidated Balance Sheets
September 30, December 31,
2001* 2000
- -------------------------------------------------------------------------------------------------------------------
(In millions)
Assets
Current Assets
Cash and cash equivalents $ 64.0 $ 182.7
Accounts receivable (net of allowance for uncollectibles
of $23.6 and $21.3 respectively) 748.1 738.5
Trading securities 196.6 189.3
Assets from energy trading activities 2,054.6 2,108.5
Fuel stocks 101.2 78.2
Materials and supplies 162.5 151.3
Prepaid taxes other than income taxes 76.5 73.5
Other 41.6 32.7
- -------------------------------------------------------------------------------------------------------------------
Total current assets 3,445.1 3,554.7
- -------------------------------------------------------------------------------------------------------------------
Investments and Other Assets
Real estate projects and investments 286.9 290.3
Investments in power projects 514.1 517.5
Financial investments 90.5 161.0
Nuclear decommissioning trust fund 235.4 228.7
Net pension asset 111.9 93.2
Investment in Orion Power Holdings, Inc. 432.6 192.0
Other 137.6 123.0
- -------------------------------------------------------------------------------------------------------------------
Total investments and other assets 1,809.0 1,605.7
- -------------------------------------------------------------------------------------------------------------------
Property, Plant and Equipment
Regulated property, plant and equipment 4,907.1 4,860.1
Nonregulated generation property, plant and equipment 6,002.4 5,279.9
Other nonregulated property, plant and equipment 209.7 173.8
Nuclear fuel (net of amortization) 121.8 128.3
Accumulated depreciation (3,923.4) (3,798.1)
- -------------------------------------------------------------------------------------------------------------------
Net property, plant and equipment 7,317.6 6,644.0
- -------------------------------------------------------------------------------------------------------------------
Deferred Charges
Regulatory assets (net) 430.7 514.9
Other 63.8 117.3
- -------------------------------------------------------------------------------------------------------------------
Total deferred charges 494.5 632.2
- -------------------------------------------------------------------------------------------------------------------
Total Assets $13,066.2 $12,436.6
===================================================================================================================
* Unaudited
See Notes to Consolidated Financial Statements.
Certain prior-period amounts have been reclassified to conform with the current
period's presentation.
4
CONSTELLATION ENERGY GROUP, INC. AND SUBSIDIARIES
PART 1 - FINANCIAL INFORMATION (CONTINUED)
Item 1 - Financial Statements
Consolidated Balance Sheets
September 30, December 31,
2001* 2000
- -------------------------------------------------------------------------------------------------------------------
(In millions)
Liabilities and Capitalization
Current Liabilities
Short-term borrowings $ 370.9 $ 243.6
Current portions of long-term debt 1,423.6 906.6
Accounts payable 708.8 695.9
Liabilities from energy trading activities 1,519.8 1,580.6
Dividends declared 22.9 66.5
Other 455.9 250.8
- -------------------------------------------------------------------------------------------------------------------
Total current liabilities 4,501.9 3,744.0
- -------------------------------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities
Deferred income taxes 1,440.1 1,339.5
Postretirement and postemployment benefits 288.3 265.2
Deferred investment tax credits 95.4 101.4
Other 217.4 484.2
- -------------------------------------------------------------------------------------------------------------------
Total deferred credits and other liabilities 2,041.2 2,190.3
- -------------------------------------------------------------------------------------------------------------------
Long-term Debt
Long-term debt of Constellation Energy 1,135.0 1,000.0
Long-term debt of nonregulated businesses 363.0 670.0
First refunding mortgage bonds of BGE 1,040.6 1,174.7
Other long-term debt of BGE 889.6 976.6
Company obligated mandatorily redeemable trust preferred
securities of subsidiary trust holding solely 7.16% debentures
of BGE due June 30, 2038 250.0 250.0
Unamortized discount and premium (4.3) (5.4)
Current portions of long-term debt (1,423.6) (906.6)
- -------------------------------------------------------------------------------------------------------------------
Total long-term debt 2,250.3 3,159.3
- -------------------------------------------------------------------------------------------------------------------
BGE Preference Stock Not Subject to Mandatory Redemption 190.0 190.0
Common Shareholders' Equity
Common stock 2,044.3 1,538.7
Retained earnings 1,891.0 1,592.3
Accumulated other comprehensive income 147.5 22.0
- -------------------------------------------------------------------------------------------------------------------
Total common shareholders' equity 4,082.8 3,153.0
- -------------------------------------------------------------------------------------------------------------------
Total capitalization 6,523.1 6,502.3
- -------------------------------------------------------------------------------------------------------------------
Total Liabilities and Capitalization $13,066.2 $12,436.6
===================================================================================================================
* Unaudited
See Notes to Consolidated Financial Statements.
Certain prior-period amounts have been reclassified to conform with the current
period's presentation.
5
CONSTELLATION ENERGY GROUP, INC. AND SUBSIDIARIES
PART 1 - FINANCIAL INFORMATION (CONTINUED)
Item 1 - Financial Statements
Consolidated Statements of Cash Flows (Unaudited)
Nine Months Ended September 30,
2001 2000
- -------------------------------------------------------------------------------------------------------------------
(In millions)
Cash Flows From Operating Activities
Net income $ 351.0 $ 259.2
Adjustments to reconcile to net cash provided by operating activities
Cumulative effect of change in accounting principle (8.5) --
Depreciation and amortization 343.1 411.1
Deferred income taxes 12.9 (31.0)
Investment tax credit adjustments (6.1) (6.3)
Deferred fuel costs 56.4 11.0
Accrued pension and postemployment benefits 19.5 18.1
Gains on sale of investments and subsidiaries (35.4) (32.6)
Deregulation transition cost -- 24.0
Equity in earnings of affiliates and joint ventures (net) (6.9) (6.3)
Changes in assets from energy trading activities 54.0 (1,034.8)
Changes in liabilities from energy trading activities (60.8) 870.0
Changes in other current assets (67.1) (243.3)
Changes in other current liabilities 170.3 270.1
Other (177.6) 79.6
- -------------------------------------------------------------------------------------------------------------------
Net cash provided by operating activities 644.8 588.8
- -------------------------------------------------------------------------------------------------------------------
Cash Flows From Investing Activities
Purchases of property, plant and equipment and other capital expenditures (1,006.5) (636.9)
Sale of (investment in) Orion 26.2 (101.5)
Contributions to nuclear decommissioning trust fund (17.6) (13.5)
Purchases of marketable equity securities (31.4) (36.3)
Sales of marketable equity securities 80.8 39.6
Other investments 38.8 20.2
- -------------------------------------------------------------------------------------------------------------------
Net cash used in investing activities (909.7) (728.4)
- -------------------------------------------------------------------------------------------------------------------
Cash Flows From Financing Activities
Net issuance of short-term borrowings 127.3 133.5
Proceeds from issuance of
Long-term debt 851.8 803.0
Common stock 504.4 35.9
Repayment of long-term debt (1,244.9) (691.8)
Common stock dividends paid (101.0) (188.5)
Other 8.6 5.2
- -------------------------------------------------------------------------------------------------------------------
Net cash provided by financing activities 146.2 97.3
- -------------------------------------------------------------------------------------------------------------------
Net Decrease in Cash and Cash Equivalents (118.7) (42.3)
Cash and Cash Equivalents at Beginning of Period 182.7 92.7
- -------------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of Period $ 64.0 $ 50.4
===================================================================================================================
Other Cash Flow Information
- ---------------------------
Cash paid during the period for:
Interest (net of amounts capitalized) $178.8 $205.0
Income taxes $139.1 $136.1
See Notes to Consolidated Financial Statements.
Certain prior-period amounts have been reclassified to conform with the current
period's presentation.
6
BALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARIES
PART 1 - FINANCIAL INFORMATION
Item 1 - Financial Statements
Consolidated Statements of Income (Unaudited)
Three Months Ended Nine Months Ended
September 30, September 30,
2001 2000 2001 2000
- -------------------------------------------------------------------------------------------------------------------
(In millions)
Revenues
Electric revenues $634.6 $598.4 $1,624.4 $1,688.4
Gas revenues 66.7 90.1 534.0 377.8
- -------------------------------------------------------------------------------------------------------------------
Total revenues 701.3 688.5 2,158.4 2,066.2
Expenses
Operating expenses:
Electric fuel and purchased energy 418.0 388.3 977.7 632.4
Gas purchased for resale 22.9 48.2 328.0 192.0
Operations and maintenance 83.3 88.0 256.9 457.5
Depreciation and amortization 53.5 63.2 166.8 312.2
Taxes other than income taxes 43.3 35.6 132.6 146.0
- -------------------------------------------------------------------------------------------------------------------
Total expenses 621.0 623.3 1,862.0 1,740.1
- -------------------------------------------------------------------------------------------------------------------
Income from Operations 80.3 65.2 296.4 326.1
Other Income 2.7 3.4 1.7 7.9
- -------------------------------------------------------------------------------------------------------------------
Income Before Fixed Charges and Income Taxes 83.0 68.6 298.1 334.0
Fixed Charges
Interest expense (net) 39.1 44.6 120.6 140.7
Allowance for borrowed funds used during construction -- (0.3) (1.4) (2.9)
- -------------------------------------------------------------------------------------------------------------------
Total fixed charges 39.1 44.3 119.2 137.8
- -------------------------------------------------------------------------------------------------------------------
Income Before Income Taxes 43.9 24.3 178.9 196.2
Income Taxes
Current 17.9 18.0 78.2 119.8
Deferred (0.6) (6.4) (6.3) (38.8)
Investment tax credit adjustments (0.5) (0.6) (1.7) (4.7)
- -------------------------------------------------------------------------------------------------------------------
Total income taxes 16.8 11.0 70.2 76.3
- -------------------------------------------------------------------------------------------------------------------
Net Income 27.1 13.3 108.7 119.9
Preference Stock Dividends 3.3 3.3 9.9 9.9
- -------------------------------------------------------------------------------------------------------------------
Earnings Applicable to Common Stock $ 23.8 $ 10.0 $ 98.8 $ 110.0
===================================================================================================================
See Notes to Consolidated Financial Statements.
Certain prior-period amounts have been reclassified to conform with the current
period's presentation.
7
BALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARIES
PART 1 - FINANCIAL INFORMATION (CONTINUED)
Item 1 - Financial Statements
Consolidated Balance Sheets
September 30, December 31,
2001* 2000
- -------------------------------------------------------------------------------------------------------------------
(In millions)
Assets
Current Assets
Cash and cash equivalents $ 23.8 $ 21.3
Accounts receivable (net of allowance for uncollectibles
of $13.4 and $13.4 respectively) 361.0 413.0
Accounts receivable, affiliated companies 66.9 8.2
Note receivable, affiliated company -- 87.0
Fuel stocks 64.4 34.1
Materials and supplies 34.9 37.3
Prepaid taxes other than income taxes 61.1 44.9
Other 11.6 4.7
- -------------------------------------------------------------------------------------------------------------------
Total current assets 623.7 650.5
- -------------------------------------------------------------------------------------------------------------------
Other Assets
Net pension asset 111.5 100.2
Receivable, affiliated company 169.0 125.0
Other 73.8 68.7
- -------------------------------------------------------------------------------------------------------------------
Other assets 354.3 293.9
- -------------------------------------------------------------------------------------------------------------------
Utility Plant
Plant in service
Electric 3,327.1 3,259.0
Gas 1,003.3 988.4
Common 484.7 532.9
- -------------------------------------------------------------------------------------------------------------------
Total plant in service 4,815.1 4,780.3
Accumulated depreciation (1,726.7) (1,700.3)
- -------------------------------------------------------------------------------------------------------------------
Net plant in service 3,088.4 3,080.0
Construction work in progress 87.5 75.3
Plant held for future use 4.5 4.5
- -------------------------------------------------------------------------------------------------------------------
Net utility plant 3,180.4 3,159.8
- -------------------------------------------------------------------------------------------------------------------
Deferred Charges
Regulatory assets (net) 430.7 514.9
Other 29.2 35.1
- -------------------------------------------------------------------------------------------------------------------
Total deferred charges 459.9 550.0
- -------------------------------------------------------------------------------------------------------------------
Total Assets $4,618.3 $4,654.2
===================================================================================================================
* Unaudited
See Notes to Consolidated Financial Statements.
Certain prior-period amounts have been reclassified to conform with the current
period's presentation.
8
BALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARIES
PART 1 - FINANCIAL INFORMATION (CONTINUED)
Item 1 - Financial Statements
Consolidated Balance Sheets
September 30, December 31,
2001* 2000
- -------------------------------------------------------------------------------------------------------------------
(In millions)
Liabilities and Capitalization
Current Liabilities
Short-term borrowings $ 107.4 $ 32.1
Current portions of long-term debt 553.2 567.6
Accounts payable 137.5 119.3
Accounts payable, affiliated companies 87.3 103.5
Customer deposits 48.2 44.4
Accrued taxes 35.6 25.0
Accrued interest 40.1 43.4
Accrued vacation costs 19.6 20.8
Other 21.4 29.6
- -------------------------------------------------------------------------------------------------------------------
Total current liabilities 1,050.3 985.7
- -------------------------------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities
Deferred income taxes 494.9 508.7
Postretirement and postemployment benefits 246.4 231.2
Deferred investment tax credits 23.2 25.0
Decommissioning of federal uranium enrichment facilities 23.7 23.7
Other 22.8 23.2
- -------------------------------------------------------------------------------------------------------------------
Total deferred credits and other liabilities 811.0 811.8
- -------------------------------------------------------------------------------------------------------------------
Long-term Debt
First refunding mortgage bonds of BGE 1,040.6 1,174.7
Other long-term debt of BGE 889.6 976.6
Company obligated mandatorily redeemable trust preferred
securities of subsidiary trust holding solely 7.16% debentures
of BGE due June 30, 2038 250.0 250.0
Long-term debt of nonregulated businesses 45.0 34.0
Unamortized discount and premium (2.1) (3.3)
Current portions of long-term debt (553.2) (567.6)
- -------------------------------------------------------------------------------------------------------------------
Total long-term debt 1,669.9 1,864.4
- -------------------------------------------------------------------------------------------------------------------
Preference Stock Not Subject to Mandatory Redemption 190.0 190.0
Common Shareholder's Equity
Common stock 462.9 465.1
Retained earnings 434.2 337.2
- -------------------------------------------------------------------------------------------------------------------
Total common shareholder's equity 897.1 802.3
- -------------------------------------------------------------------------------------------------------------------
Total capitalization 2,757.0 2,856.7
- -------------------------------------------------------------------------------------------------------------------
Total Liabilities and Capitalization $4,618.3 $4,654.2
===================================================================================================================
* Unaudited
See Notes to Consolidated Financial Statements.
Certain prior-period amounts have been reclassified to conform with the current
period's presentation.
9
BALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARIES
PART 1 - FINANCIAL INFORMATION (CONTINUED)
Item 1 - Financial Statements
Consolidated Statements of Cash Flows (Unaudited)
Nine Months Ended September 30,
2001 2000
- -------------------------------------------------------------------------------------------------------------------
(In millions)
Cash Flows From Operating Activities
Net income $108.7 $119.9
Adjustments to reconcile to net cash provided by operating activities
Depreciation and amortization 168.5 338.2
Deferred income taxes (6.3) (38.8)
Investment tax credit adjustments (1.7) (4.7)
Deferred fuel costs 56.4 11.0
Accrued pension and postemployment benefits 8.1 14.9
Allowance for equity funds used during construction (2.2) (2.1)
Changes in other current assets (103.0) (127.0)
Changes in other current liabilities 6.7 158.1
Other 8.1 6.4
- -------------------------------------------------------------------------------------------------------------------
Net cash provided by operating activities 243.3 475.9
- -------------------------------------------------------------------------------------------------------------------
Cash Flows From Investing Activities
Utility construction expenditures (excluding AFC) (172.0) (238.9)
Nuclear fuel expenditures -- (39.5)
Contributions to nuclear decommissioning trust fund -- (8.8)
Other (11.0) (6.0)
- -------------------------------------------------------------------------------------------------------------------
Net cash used in investing activities (183.0) (293.2)
- -------------------------------------------------------------------------------------------------------------------
Cash Flows From Financing Activities
Net issuance of short-term borrowings 75.3 129.0
Proceeds from issuance of long-term debt 210.9 -
Repayment of long-term debt (334.1) (121.7)
Preference stock dividends paid (9.9) (9.9)
Distributions to Constellation Energy -- (188.5)
Other -- 1.8
- -------------------------------------------------------------------------------------------------------------------
Net cash used in financing activities (57.8) (189.3)
- -------------------------------------------------------------------------------------------------------------------
Net Increase (Decrease) in Cash and Cash Equivalents 2.5 (6.6)
Cash and Cash Equivalents at Beginning of Period 21.3 23.5
- -------------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of Period $ 23.8 $ 16.9
===================================================================================================================
Other Cash Flow Information
- ---------------------------
Cash paid during the period for:
Interest (net of amounts capitalized) $122.8 $147.0
Income taxes $ 66.9 $111.5
Non-Cash Transactions
- ---------------------
On July 1, 2000, BGE transferred $1,578.4 million of generation assets, net of
associated liabilities, to nonregulated affiliates of Constellation Energy
pursuant to the Maryland PSC's Restructuring Order.
See Notes to Consolidated Financial Statements.
Certain prior-period amounts have been reclassified to conform with the current
period's presentation.
10
Notes to Consolidated Financial Statements
- ------------------------------------------
Weather conditions can have a great impact on our results for interim periods.
This means that results for interim periods do not necessarily represent results
to be expected for the year.
Our interim financial statements on the previous pages reflect all
adjustments that Management believes are necessary for the fair presentation of
the financial position and results of operations for the interim periods
presented. These adjustments are of a normal recurring nature.
Holding Company Formation
- -------------------------
On April 30, 1999, Constellation Energy(R) Group, Inc. (Constellation Energy)
became the holding company for Baltimore Gas and Electric Company (BGE(R)) and
its subsidiaries. BGE's outstanding common stock automatically became shares of
common stock of Constellation Energy. BGE's debt securities, obligated
mandatorily redeemable trust preferred securities, and preference stock remain
securities of BGE, or its subsidiaries.
Basis of Presentation
- ---------------------
This Quarterly Report on Form 10-Q is a combined report of Constellation Energy
and BGE. The consolidated financial statements of Constellation Energy include
the accounts of Constellation Energy, BGE and its subsidiaries, Constellation
Enterprises, Inc. and its subsidiaries, and Constellation Nuclear, LLC and its
subsidiaries. The consolidated financial statements of BGE include the accounts
of BGE, District Chilled Water General Partnership (ComfortLink), and BGE
Capital Trust I.
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.
Deregulation of Electric Generation
- -----------------------------------
On April 8, 1999, Maryland enacted legislation authorizing customer choice and
competition among electric suppliers. In addition, on November 10, 1999, the
Maryland Public Service Commission (Maryland PSC) issued a Restructuring Order
that resolved the major issues surrounding electric restructuring. Effective
July 1, 2000, the state of Maryland implemented customer choice for electric
suppliers. We discuss the implications of customer choice and the Restructuring
Order further in Management's Discussion and Analysis beginning on page 20.
Please also refer to the Legal Proceedings section on page 39 for a discussion
regarding an appeal of the Restructuring Order.
Subsequent Events
- -----------------
Business Separation
- -------------------
On October 26, 2001, we announced the decision to remain a single company and
canceled prior plans to separate our domestic merchant energy business from our
remaining businesses.
We also announced the termination of our power advisory relationship with
Goldman Sachs. We paid Goldman Sachs a total of $355 million, representing $196
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. As a result, in the fourth quarter of
2001, we expect to recognize an expense of approximately $200 million pre-tax,
or $.79 per share, related to the termination of the contract with Goldman
Sachs. In light of this transaction, Goldman Sachs will no longer make the
equity investment in our domestic merchant energy business as previously
announced.
Acquisition of Nine Mile Point
- ------------------------------
On November 7, 2001, we completed our purchase of the Nine Mile Point Nuclear
Station (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 for
$762 million, including $87 million for fuel. Approximately one-half of the
purchase price, or $380 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 include: 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 of the plant
are based on operation of the individual units.
11
Sale of Guatemalan Operations
- -----------------------------
On November 8, 2001, we sold our Guatemalan power plant operations to an
affiliate of Duke Energy International, L.L.C., 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
domestic merchant energy business and our retail energy businesses, including
BGE. As a result of this transaction, we are no longer committed to making
significant future capital investments in a non-core operation. We will record
an after-tax loss of approximately $28 million in the fourth quarter of 2001,
resulting from this sale.
Early Retirement Programs
- -------------------------
We continue to evaluate cost-cutting measures to reduce our workforce. As part
of this initiative, our domestic merchant energy business and BGE recently
announced Voluntary Special Early Retirement Programs (VSERPs) to provide
enhanced retirement benefits to certain eligible participants that elect to
retire on February 1, 2002. The programs are being offered to accelerate the
pace of our efforts to reduce our operating costs to remain competitive in our
business environment. We will reflect the financial impacts of the VSERPs in the
fourth quarter of 2001.
Bethlehem Steel
- ---------------
On October 15, 2001, Bethlehem Steel Corporation filed for reorganization
under Chapter 11 of the U.S. Bankruptcy Code. Bethlehem Steel is BGE's largest
customer, accounting for approximately three percent of electric revenues and
one percent of gas revenues. At September 30, 2001, our receivable balance from
Bethlehem Steel was approximately $5 million.
We discuss other subsequent events in the related sections of these Notes to
Consolidated Financial Statements.
- --------------------------------------------------------------------------------
Information by Operating Segment
- --------------------------------
Our reportable operating segments are - Domestic Merchant Energy, Regulated
Electric, and Regulated Gas:
o Our nonregulated domestic merchant energy business in North America:
- provides power marketing, structured transactions, and risk management
services,
- develops, owns, and operates domestic power projects, and
- provides nuclear consulting services.
o Our regulated electric business purchases, distributes and sells
electricity in Maryland, and
o Our regulated gas business purchases, transports, and sells natural gas
in Maryland.
Effective July 1, 2000, the financial results of the electric generation
portion of our business are included in the domestic 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 and own 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.
12
Domestic Unallocated
Merchant Regulated Regulated Other Corporate
Energy Electric Gas Nonregulated Items and
Business Business Business Businesses Eliminations Consolidated
- --------------------------- -------------- -------------- --------------- ------------- -------------- ------------
For the three months ended September 30, (In millions)
2001
Unaffiliated revenues $ 215.9 $ 634.4 $ 66.6 $ 119.2 $ - $ 1,036.1
Intersegment revenues 401.4 0.2 0.1 - (401.7) -
- ---------------------------- ------------- -------------- --------------- ------------- ------------ --------------
Total revenues 617.3 634.6 66.7 119.2 (401.7) 1,036.1
Net income (loss) 144.9 27.3 (2.3) (6.3) - 163.6
2000
Unaffiliated revenues $ 119.4 $ 598.2 $ 86.7 $ 164.3 $ - $ 968.6
Intersegment revenues 380.0 0.2 3.4 9.8 (393.4) -
- ---------------------------- ------------- -------------- --------------- ------------- ------------ --------------
Total revenues 499.4 598.4 90.1 174.1 (393.4) 968.6
Net income (loss) 129.9 15.4 (4.6) 6.8 - 147.5
For the nine months ended September 30,
2001
Unaffiliated revenues $ 414.9 $1,624.0 $528.5 $ 459.0 $ - $ 3,026.4
Intersegment revenues 933.9 0.4 5.5 1.9 (941.7) -
- ---------------------------- ------------- -------------- --------------- ------------- ------------ --------------
Total revenues 1,348.8 1,624.4 534.0 460.9 (941.7) 3,026.4
Cumulative effect of change
in accounting principle - - - 8.5 - 8.5
Net income 239.7 73.0 29.4 8.9 - 351.0
2000
Unaffiliated revenues $ 293.1 $1,688.0 $372.8 $ 475.3 $ - $ 2,829.2
Intersegment revenues 380.0 0.4 5.0 15.8 (401.2) -
- ---------------------------- ------------- -------------- --------------- ------------- ------------ --------------
Total revenues 673.1 1,688.4 377.8 491.1 (401.2) 2,829.2
Net income (loss) (a) 150.0 93.2 18.1 (2.1) - 259.2
At September 30, 2001
Segment assets $ 7,321.7 $ 3,469.0 $ 1,090.3 $ 1,508.4 $ (323.2) $13,066.2
At December 31, 2000
Segment assets $ 6,786.6 $ 3,392.3 $ 1,089.9 $ 1,491.5 $ (323.7) $12,436.6
(a)
(a) Our regulated electric business recorded an expense of $4.2 million related
to employees that elected to participate in a Targeted Voluntary Special
Early Retirement Program. In addition, our domestic merchant energy
business recorded a $15.0 million deregulation transition cost incurred by
our power marketing operation.
Certain prior-period amounts have been reclassified to conform with the current
period's presentation.
13
Financing Activity
- ------------------
Constellation Energy
- --------------------
During the period from January 1, 2001 through the date of this report, we
issued a total of 13.2 million shares of common stock, without par value for net
proceeds of $504.4 million. We issued 12.0 million shares through a secondary
offering and the remaining 1.2 million shares were issued under our Continuous
Offering Program for Stock and the Shareholder Investment Plan.
Constellation Energy issued and redeemed prior to their maturity the
following notes during the period from January 1, 2001 through the date of this
report:
Date Net
Issued/ Proceeds/
Principal Redeemed Payments
- ------------------------------ -------- --------- --------
(In millions)
Issued:
Floating Rate Notes due 2002 $400.0 1/01 $399.7
Floating Rate Notes due 2002 235.0 4/01 234.7
Redeemed:
Floating Rate Reset Notes
due 2002 $200.0 1/01 $200.0
Extendible Notes due 2010 300.0 6/01 300.0
Floating Rate Notes due 2003 200.0 10/01 200.0
In anticipation of separating our domestic merchant energy business from our
remaining 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 will use this facility primarily to fund capital expenditures, and
working capital requirements, including commercial paper support, for the
domestic merchant energy business. We do not expect to use the facility to
redeem Constellation Energy's outstanding long-term debt and to repay commercial
paper borrowings as previously stated.
We discuss the cancellation of our plans to separate in the Recent Events
section of Management's Discussion and Analysis on page 21.
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. Constellation Energy also has an existing
$188.5 million, multi-year revolving credit facility available for short-term
and long-term needs, including letters of credit. As of the date of this report,
letters of credit that totaled $269.7 million were issued under all of our
facilities.
Additionally, since September 30, 2001, we used existing financing sources
to fund the $355 million payment to Goldman Sachs for the termination of the
power business services agreement and for the $380 million paid for the
acquisition of Nine Mile Point.
Constellation Energy has issued guarantees in an amount up to $1.5 billion
primarily related to credit facilities and contractual performance of our
domestic merchant energy business. However, the actual subsidiary liabilities
related to these guarantees totaled $253.7 million at September 30, 2001.
BGE and Nonregulated Businesses
- -------------------------------
BGE issued and redeemed prior to their maturity the following notes during the
period from January 1, 2001 through the date of this report:
Date Net
Issued/ Proceeds/
Principal Redeemed Payments
- ------------------------------ -------- --------- --------
(In millions)
Issued:
Floating Rate Notes due 2002 $200.0 5/01 $200.0
Redeemed:
Floating Rate Reset Notes
due 2001 $200.0 5/01 $200.0
In conjunction with the July 1, 2000 transfer of generation assets, BGE
currently is contingently liable for $276 million of the tax exempt debt that
was assigned to nonregulated affiliates of Constellation Energy as discussed
further in the Current Issues -Electric Competition section of Management's
Discussion and Analysis on page 22. In the future, BGE may purchase some of its
long-term debt or preference stock in the market. This will depend on market
conditions and BGE's capital structure.
Please refer to the Funding for Capital Requirements section of Management's
Discussion and Analysis on page 37 for additional information about the debt of
BGE and our nonregulated businesses.
Commitments
- -----------
Our domestic merchant energy business has committed to contribute additional
capital and to make additional loans to some affiliates, joint ventures, and
partnerships in which we have an interest. At September 30, 2001, the total
amount of investment requirements committed to by our domestic merchant energy
business was $183.3 million.
14
Environmental Matters
- ---------------------
Clean Air
- ---------
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 our facilities and projects. Various provisions may require
permits, inspections or installation of additional pollution control technology.
Because our 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.
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. 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.
Many of our assets 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 by May of 2002, emissions reduction equipment in order to meet
Maryland regulations issued pursuant to EPA's rule. The Keystone plant in
Pennsylvania is installing emissions reduction equipment by 2003 to meet
Pennsylvania regulations issued pursuant to EPA's rule.
We currently estimate that the controls needed at our generating plants to
meet the NOx emission reduction requirements will cost approximately $285
million. Through September 30, 2001, we have spent approximately $180 million to
meet these reduction requirements.
In July 1997, the EPA published new National Ambient Air Quality Standards
for very fine particulates and revised standards for ozone attainment. While
these standards may require increased controls at our fossil generating plants
in the future, implementation, if required, could be delayed for several years.
We cannot estimate the cost of these increased controls at this time because the
states, including Maryland, Pennsylvania, and California, still need to
determine what reductions in pollutants will be necessary to meet the EPA
standards.
The EPA decided to control mercury emissions from coal-fired plants. The EPA
expects to issue final regulations in 2004 and compliance could be required by
approximately 2007. The costs of these controls cannot be estimated at this time
since the level of control or systems to implement them have not yet been
established, but such costs could be material.
Over the past two years, the EPA and several states have filed suits against
a number of coal-fired power plants in midwestern 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, 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 the Pennsylvania waste-coal burning plants in
which we have an ownership interest. We have provided the EPA the requested
information. 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 other suits, 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. We believe our generating plants have
been operated in accordance with the Clean Air Act and the rules implementing
the Clean Air Act.
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, BGE signed a consent
order with the Maryland Department of the Environment (MDE) that requires us to
implement remedial action plans for contamination at and around the Spring
Gardens site, located in Baltimore, Maryland. BGE 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
15
contamination are estimated to total $47 million. BGE has recorded these costs
as a liability and has deferred these costs, net of accumulated amortization and
amounts 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 5 of our 2000 Annual Report on Form
10-K. Through September 30, 2001, we have spent approximately $36.6 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.
Other potential environmental liabilities and pending environmental actions
are described further in our 2000 Annual Report on Form 10-K in Item 1. Business
- - Environmental Matters.
Nuclear Insurance
- -----------------
If there was an accident or an extended outage at any unit of the Calvert Cliffs
Nuclear Power Plant (Calvert Cliffs) or the Nine Mile Point Nuclear Power Plant,
it could have a substantial adverse financial effect on us. The primary
contingencies that would result from an incident at Calvert Cliffs or Nine Mile
Point could include:
o physical damage to the plants,
o recoverability of replacement power costs, and
o our liability to third parties for property damage and bodily injury.
We have insurance policies that cover these contingencies, but the policies
have certain industry standard exclusions, such as ordinary wear and tear,
intentional acts, and war. Terrorist acts, while not excluded, are covered as a
common occurrence, meaning that if terrorist acts occur against one or more
commercial nuclear power plants in the country within a 12 month period, they
will be treated as one event and the owners of the plants will share the full
limit of the policy (currently $3.24 billion). Furthermore, the costs that could
result from a covered major accident or a covered extended outage at either of
the Calvert Cliffs or Nine Mile Point units could exceed our insurance coverage
limits.
Insurance for Nuclear Facilities and Third Party Claims
- -------------------------------------------------------
For physical damage to Calvert Cliffs or Nine Mile Point, we have $2.75 billion
of property insurance for each plant from an industry mutual insurance company.
If an outage at any unit at Calvert Cliffs or Nine Mile Point is caused by an
insured physical damage loss and lasts more than 12 weeks, we have insurance
coverage for replacement power costs up to $490.0 million per unit ($412.6
million for Unit 2 of Nine Mile Point), provided by an industry mutual insurance
company. This amount can be reduced by up to $98.0 million per unit ($82.5
million for Unit 2 of Nine Mile Point) if an outage at both units of either
plant is caused by a single insured physical damage loss. 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 $77
million.
In addition we, as well as others, could be charged for a portion of any
third party claims associated with a nuclear incident at any commercial nuclear
power plant in the country. At the date of this report, the limit for third
party claims from a nuclear incident is $9.54 billion under the provisions of
the Price Anderson Act. If third party claims exceed $200 million (the amount of
primary insurance), our share of the total liability for third party claims
could be up to $352.4 million per incident. That amount would be payable at a
rate of $40 million per year.
Some of the provisions of the Price Anderson Act expire in August 2002, and
it 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.
Insurance for Worker Radiation Claims
- -------------------------------------
As an operator of two commercial nuclear power plants in the United States, we
are required to purchase insurance to cover radiation injury claims of certain
nuclear workers. On January 1, 1998, a new insurance policy became effective for
all operators requiring coverage for current operations. Waiving the right to
make additional claims under the old policy was a condition for acceptance under
the new policy. We describe both 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 insurance policies. 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 for
the next seven years. If radiation injury claims under these old policies
exceed the policy reserves, all policyholders could be assessed, with our
share being up to $6.3 million.
If claims under these policies exceed the coverage limits, the provisions of
the Price Anderson Act (discussed in this section) would apply.
The sellers of Nine Mile Point retain the liabilities for existing and
potential claims that occurred prior to the closing date of the sale.
16
Recoverability of Electric Fuel Costs
- -------------------------------------
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 (included as an asset or liability on the Consolidated Balance
Sheets and excluded from the Consolidated Statements of Income) 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.
California Power Purchase Agreements
- ------------------------------------
Our domestic generation operation has $303.0 million invested in 14 operating
projects that sell electricity in California under power purchase agreements
called "Interim Standard Offer No. 4 (SO4)" agreements to Southern California
Edison (SCE) and Pacific Gas & Electric (PGE).
Under these agreements, the electricity rates changed from fixed to variable
rates beginning in 1996. In 2000, the last four projects transitioned to
variable rates. Due in part to uncertainties in California, prices have been
volatile.
The projects recently entered into agreements with SCE and PGE that provide
for five-year fixed price payments averaging $53.70 per megawatt-hour plus the
stated capacity payments in the original SO4 contracts. These agreements also
provide conditions for the payment of all past due amounts plus interest which
the projects expect to collect in the next two years.
We discuss the developments in California in the Current Issues - Other
States section on page 23. We also describe these projects and the transition
process in Note 3 and Note 10 of our 2000 Annual Report on Form 10-K.
Related Party Transactions - BGE
- --------------------------------
Income Statement
- ----------------
Under the Restructuring Order, BGE is providing standard offer service to
customers at fixed rates over various time periods during the transition period
from July 1, 2000 to June 30, 2006, for those customers that do not choose an
alternate supplier. Constellation Power Source is under contract to provide BGE
with the energy and capacity required to meet its standard offer service
obligations for the first three years of the transition period, and 90% of the
energy and capacity for the final three years (July 1, 2003 to June 30, 2006) of
the transition period. The cost of BGE's purchased energy from nonregulated
affiliates of Constellation Energy to meet its standard offer service obligation
was $402.8 million for the quarter and $935.3 million for the nine months ended
September 30, 2001 compared to $387.4 million for the quarter and nine months
ended September 30, 2000.
In addition, Constellation Energy charges BGE for certain corporate
functions. Certain costs are directly charged to BGE. We allocate other
corporate function costs based on a total percentage of expected use by BGE.
Management believes this method of allocation is reasonable and approximates the
cost BGE would have incurred as an unaffiliated entity. These costs were $4.0
million for the quarter ended September 30, 2001 compared to $9.6 million for
the same period in 2000 and $14.2 million for the nine months ended September
30, 2001 compared to $16.9 million for the same period in 2000.
Balance Sheet
- -------------
As a result of the deregulation of electric generation, BGE transferred its
generation assets to nonregulated affiliates of Constellation Energy effective
July 1, 2000. In conjunction with this transfer, Constellation Power Source
Generation, Inc. issued approximately $366.0 million in unsecured promissory
notes to BGE. All of these notes have been repaid by Constellation Power Source
Generation, Inc. The proceeds were used to service current maturities of certain
BGE long-term debt.
Amounts related to corporate functions performed at the Constellation Energy
holding company, BGE's purchases to meet its standard offer service obligation,
and BGE's charges to Constellation Energy and its nonregulated affiliates for
certain services it provides them result in the affiliated company balances on
BGE's Consolidated Balance Sheets. Management believes its allocation methods
are reasonable and approximate the costs that would be charged to unaffiliated
entities.
Accounting Standard Adopted
- ---------------------------
On January 1, 2001, we adopted Statement of Financial Accounting Standards
(SFAS) No. 133, Accounting for Derivative Instruments and Hedging Activities, 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 and Hedging
Activities section on page 18. 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.
17
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 Power Holdings, Inc. (Orion). The warrant has an exercise price of $10 per
share and expires on April 24, 2010. The warrant was received in conjunction
with our investment in Orion. As part of the proposed sale of Orion to Reliant
Resources, Inc, we expect to receive cash equal to the difference between the
merger consideration 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 domestic merchant energy
business. We discuss our risk management for derivatives and hedging activities
below.
Risk Management and Hedging Activities
- --------------------------------------
Our domestic merchant energy business is exposed to market risk from the power
marketing operation of Constellation Power Source and from our electric
generation operations. Constellation Power Source manages the commodity price
risk inherent in its power marketing activities on a portfolio basis, subject to
established trading and risk management policies.
Constellation Power Source 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) amount; and
o option contracts, which convey the right to buy or sell a commodity,
financial instrument, or index at a predetermined price.
Our domestic merchant energy business conducts electric generation
operations primarily through Constellation Power Source Generation, Calvert
Cliffs, Constellation Power, and beginning in November 2001, Nine Mile Point.
Presently, we expect to use the majority of the generating capacity controlled
by our domestic merchant energy business to provide standard offer service to
BGE or to be sold back to the sellers of Nine Mile Point to service their load
requirements. However, beginning in July 2002, we expect approximately 1,000
megawatts of industrial customer load will leave BGE's standard offer service.
Going forward, our domestic merchant energy business will supply 100% of the
standard offer service to BGE through June 30, 2003 and 90% from July 1, 2003
through June 30, 2006. Additionally, we plan to expand our generation
operations. As a result, our domestic merchant energy business has a substantial
and increasing amount of generating capacity that is subject to future changes
in wholesale electricity prices and has fuel requirements that are subject to
future changes in coal, natural gas, and oil prices.
Constellation Power Source manages the commodity price risk of our electric
generation operations as part of its overall portfolio. 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. Our objectives for entering into such hedges include
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 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.
As of September 30, 2001, our domestic merchant energy business had
designated certain fixed-price forward electricity sale contracts as a cash-flow
hedge of forecasted sales of electricity for the years 2002 through 2010. We
record derivatives used for hedging activities in "Other Assets" and in "Other
Deferred Credits and Other Liabilities" on the Consolidated Balance Sheets.
At September 30, 2001, we recorded net losses of $2.2 million on these
hedges in "Accumulated Other Comprehensive Income". We expect to reclassify $2.3
million of net gains on cash flow hedges from "Other Comprehensive Income" into
earnings during the next twelve months based on the market prices at September
30, 2001. However, the actual amount reclassified into earnings could vary from
the amounts recorded at September 30, 2001 due to future changes in the market
prices. For the quarter and nine months ended September 30, 2001, there was no
hedge ineffectiveness recognized in earnings. We discuss our market risk in Item
7. Management's Discussion and Analysis - Market Risk of our 2000 Annual Report
on Form 10-K.
18
In November 2001, we entered into forward starting interest rate swap
contracts to manage a portion of our interest rate exposure for the anticipated
borrowings related to the refinancing of our existing $2.5 billion credit
facility. 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.
These swaps are designated as cash-flow hedges under SFAS No. 133, with
gains or losses recorded in "Accumulated Other Comprehensive Income" in
anticipation of planned financing transactions. Any gain or loss on the hedges
will be reclassified into earnings and included in "Interest Expense" from
"Other Comprehensive Income" during the periods in which the interest payments
being hedged occur.
Accounting Standards Issued
- ---------------------------
In October 2001, the FASB issued SFAS No. 144, Accounting for the Impairment or
Disposal of Long-Lived Assets, that 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. Currently, we are evaluating this statement and have not
determined the impact on our financial results.
In July 2001, the FASB issued SFAS No. 141, Business Combinations, SFAS
No. 142, Goodwill and Other Intangible Assets, and SFAS No. 143, Accounting for
Obligations Associated with the Retirement of Long-Lived Assets.
SFAS No. 141 requires that all business combinations 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.
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 these statements 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
the impact on our financial results.
Accounting for the Investment in Orion
- --------------------------------------
Effective June 1, 2001, we changed our accounting for the investment in Orion
from the equity method to the cost method, subject to the fair value
requirements of SFAS No. 115, Accounting for Certain Investments in Debt and
Equity Securities. 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. Under SFAS No. 115,
we classify our investment in Orion as available-for-sale securities and record
any unrealized gains or losses in "Accumulated Other Comprehensive Income" on
our Consolidated Balance Sheets. At September 30, 2001, the unrealized gain on
our investment in Orion was $141.5 million.
19
Item 2. Management's Discussion
- -------------------------------
Management's Discussion and Analysis of Financial Condition and Results of
- --------------------------------------------------------------------------
Operations
- ----------
Introduction
- ------------
Constellation Energy Group, Inc. (Constellation Energy) is a diversified North
American energy company. Constellation Energy conducts its business through
various subsidiaries that primarily include a domestic merchant energy business
and Baltimore Gas and Electric Company (BGE). Our domestic merchant energy
business is focused mostly on power marketing and merchant generation in North
America. BGE is an electric and gas public utility distribution 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 the Notes to
Consolidated Financial Statements on page 12.
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. This Quarterly Report on Form 10-Q is a combined report of
Constellation Energy and BGE.
Effective July 1, 2000, electric generation was deregulated in Maryland.
Also, on July 1, 2000, BGE transferred all of its generation assets and related
liabilities at book value to our domestic merchant energy business. We discuss
the deregulation of electric generation in the Current Issues section on page
22.
As a result of these changes, our domestic merchant energy business includes
the:
o wholesale power marketing, structured transactions, and risk management
activities of Constellation Power Source, Inc.,
o domestic power projects of Constellation Investments, Inc. and
Constellation Power, Inc. and subsidiaries,
o fossil and hydroelectric generating assets of Constellation Power Source
Generation, Inc.,
o nuclear generating assets of Calvert Cliffs Nuclear Power Plant, Inc.,
and effective in November 2001 Nine Mile Point Nuclear Station, LLC, and
o nuclear consulting services of Constellation Nuclear Services, Inc.
Also, effective July 1, 2000, the financial results of the electric
generation portion of our business are included in the domestic merchant energy
business. Prior to that date, the financial results of electric generation were
included in BGE's regulated electric business.
BGE remains a regulated electric and gas public utility company.
Our other nonregulated businesses include the:
o energy products and services of Constellation Energy Source, Inc.,
o home products, commercial building systems, and residential and
commercial electric and gas retail marketing of BGE Home Products &
Services, Inc. and subsidiaries,
o ComfortLink general partnership, in which BGE is a partner, that provides
cooling services for commercial customers in Baltimore,
o financial investments of Constellation Investments,
o real estate and senior-living facilities of Constellation Real Estate
Group, Inc., and
o interests in Latin America power generation and distribution projects and
investments of Constellation Power and subsidiaries.
In this discussion and analysis, we explain the general financial condition
and the results of operations for Constellation Energy and BGE including:
o what factors affect our businesses,
o what our earnings and costs were in the periods presented,
o why earnings and costs changed between periods,
o where our earnings came from,
o how all of this affects our overall financial condition,
o what we expect our expenditures for capital projects to be in the future,
and
o where we expect to get cash for future capital expenditures.
As you read this discussion and analysis, refer to our Consolidated
Statements of Income on page 3, which present the results of our operations for
the quarters and nine months ended September 30, 2001 and 2000. We analyze and
explain the differences between periods in the specific line items of the
Consolidated Statements of Income. Our analysis is important in making decisions
about your investments in Constellation Energy and/or BGE.
Also, this discussion and analysis is based on the operation of the electric
generation portion of our utility business under rate regulation through June
30, 2000. Our regulated electric business changed as we transferred our electric
generation assets and related liabilities to our domestic merchant energy
business and we entered into retail customer choice for electric generation
effective July 1, 2000. Accordingly, the results of operations and financial
condition described in this discussion and analysis are not necessarily
indicative of future performance.
20
Recent Events
- -------------
Business Separation
- -------------------
On October 26, 2001, we announced the decision to remain a single company and
canceled prior plans to separate our domestic merchant energy business from our
remaining businesses. In the past year, the utility industry, energy markets,
and general economy have changed and we believe that maintaining our current
corporate structure provides a better platform of size, strength, and stability
to execute our strategies.
We also announced the termination of our power advisory relationship with
Goldman Sachs. We paid Goldman Sachs a total of $355 million, representing $196
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. We used existing financing sources to
fund this payment. As a result, in the fourth quarter of 2001, we expect to
recognize an expense of approximately $200 million pre-tax, or $.79 per share,
related to the termination of the contract with Goldman Sachs. In light of this
transaction, Goldman Sachs will no longer make the equity investment in our
domestic merchant energy business as previously announced.
Acquisition of Nine Mile Point
- ------------------------------
On November 7, 2001, we completed our purchase of the Nine Mile Point Nuclear
Station (Nine Mile Point) located in Scriba, New York. 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 for $762 million, including $87
million for fuel. Approximately one-half of the purchase price, or $380 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%. As a result,
we own 1,550 megawatts of Nine Mile Point's 1,757 megawatts of total generating
capacity.
The sellers transferred approximately $442 million in decommissioning funds.
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.
We discuss the acquisition of Nine Mile Point further in the Notes to the
Financial Statements on page 11.
Sale of Guatemalan Operations
- -----------------------------
On November 8, 2001, we sold our Guatemalan power plant operations to an
affiliate of Duke Energy International, L.L.C., 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
domestic merchant energy business and our retail energy businesses, including
BGE. As a result of this transaction, we are no longer committed to making
significant future capital investments in a non-core operation. We will record
an after-tax loss of approximately $28 million, or $.17 per share, in the fourth
quarter of 2001, resulting from this sale.
Early Retirement Programs
- -------------------------
We continue to evaluate cost-cutting measures to reduce our workforce. As part
of this initiative, our domestic merchant energy business and BGE recently
announced Voluntary Special Early Retirement Programs (VSERPs) to provide
enhanced retirement benefits to certain eligible participants that elect to
retire on February 1, 2002. The programs are being offered to accelerate the
pace of our efforts to reduce our operating costs to remain competitive in our
business environment. We will reflect the financial impacts of the VSERPs in the
fourth quarter of 2001.
Investment in Orion
- -------------------
In September 2001, Orion entered into an agreement with Reliant Resources, Inc.,
under which Reliant Resources will acquire all of the outstanding shares of
Orion for $26.80 per share. The companies have publicly announced that they
expect to complete the transaction in early 2002. We have agreed to vote in
favor of this transaction. We expect to recognize a gain on the sale of our
investment of approximately $154 million at the close of this transaction.
Bethlehem Steel
- ---------------
On October 15, 2001, Bethlehem Steel Corporation filed for reorganization under
Chapter 11 of the U.S. Bankruptcy Code. Bethlehem Steel is BGE's largest
customer, accounting for approximately three percent of electric revenues and
one percent of gas revenues. At September 30, 2001, our receivable balance from
Bethlehem Steel was approximately $5 million. However, we cannot determine the
ultimate impact of the bankruptcy filing on our financial results at this time
with respect to the collectibility of receivables or the continuation of
Bethlehem Steel's operations at its Sparrows Point plant, located in Baltimore
Maryland.
New President and Chief Executive Officer
- -----------------------------------------
Effective November 1, 2001, Mayo A. Shattuck, III was elected President and
Chief Executive Officer of Constellation Energy. Christian H. Poindexter remains
as Chairman of the Board. Mr. Shattuck has been a Director of Constellation
Energy for seven years. Prior to joining Constellation Energy, he was Global
Head of Investment Banking for Deutsche Bank and Co-Chairman and Co-Chief
Executive Officer of DB Alex. Brown and Deutsche Bank Securities.
21
Strategy
- --------
Customer choice and regulatory change significantly impact our business. In
response, we regularly evaluate our strategies with two goals in mind: to
improve our competitive position, and to anticipate and adapt to business
environment and regulatory changes.
As a result of evaluating our strategies, on October 26, 2001, we announced
the decision to remain a single company and canceled prior plans to separate our
domestic merchant energy business from our other businesses and terminated our
power advisory relationship with Goldman Sachs as previously discussed in the
Recent Events section on page 21.
The growth of BGE and our retail energy services businesses is expected
through focused and disciplined expansion in its service territory. However, our
primary growth strategy centers on our domestic merchant energy business.
The strategy for our domestic merchant energy business continues to be a
leading competitive provider of energy solutions for wholesale customers in
North America. To achieve this, our domestic merchant energy business expects to
continue to integrate our generation assets with our marketing and risk
management operations supported by geographic, fuel, and dispatch
diversification. We also expect to accomplish this growth through structured
transactions to wholesale customers and by acquiring and developing additional
generating facilities when necessary to support our marketing operation. This
business will focus on states with strong growth in energy demand and that
provide opportunities through ongoing deregulation and the creation of
competitive markets. Delays in, or the ultimate form of, deregulation of
electric generation in various states (which continues to be impacted by the
events in California) may affect our domestic merchant energy business growth
initiatives. Currently, our domestic merchant energy business controls over
11,500 megawatts of generation including the recent acquisition of 1,550
megawatts of the generating capacity at Nine Mile Point and 1,100 megawatts of
natural gas-fired peaking capacity that commenced operations in the Mid-Atlantic
and Mid-West regions during mid-summer 2001.
We also have approximately 3,000 megawatts of natural gas-fired peaking and
combined cycle production facilities in various regions of North America under
construction and several projects in development.
We also might consider one or more of the following strategies:
o the complete or partial separation of BGE's transmission function,
o mergers or acquisitions of utility or non-utility businesses or assets,
and
o sale of generation assets or one or more businesses.
- --------------------------------------------------------------------------------
Current Issues
- --------------
With the shift toward customer choice, competition, and the growth of our
domestic merchant energy business, various factors affect our financial results.
We discuss these various factors in the Forward Looking Statements section on
page 40.
In this section, we discuss in more detail several issues that affect our
businesses.
Electric Competition
- --------------------
We are facing electric competition on various fronts, including:
o the construction of generating units to meet increased demand for
electricity,
o the sale of electricity in wholesale power markets,
o competing with other energy suppliers, and
o electric sales to retail customers.
Maryland
- --------
On April 8, 1999, Maryland enacted the Electric Customer Choice and Competition
Act of 1999 (the "Act") and accompanying tax legislation that has 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 accompanying tax legislation is discussed in
detail in Note 4 of our 2000 Annual Report on Form 10-K.
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 discussed in Note 4 of our 2000 Annual Report on Form
10-K.
As a result of the deregulation of electric generation, the following
occurred effective July 1, 2000:
o All customers can choose their electric energy supplier. 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. These rates will not change before July 2006.
22
o BGE transferred, at book value, its nuclear generating assets, its
nuclear decommissioning trust fund, and related liabilities to Calvert
Cliffs Nuclear Power Plant, Inc. In addition, BGE transferred, at book
value, its fossil generating assets and related liabilities and its
partial ownership interest in two coal plants and a hydroelectric plant
located in Pennsylvania to Constellation Power Source Generation.
In total, these generating assets represent about 6,240 megawatts of
generation capacity with a total net book value at June 30, 2000 of
approximately $2.4 billion.
o BGE assigned approximately $47 million to Calvert Cliffs Nuclear Power
Plant, Inc. and $231 million to Constellation Power Source Generation of
tax-exempt debt related to the transferred assets. Also, Constellation
Power Source Generation issued approximately $366 million in unsecured
promissory notes to BGE. All of these notes have been repaid by
Constellation Power Source Generation. The proceeds were used to service
the current maturities of certain BGE long-term debt.
o BGE transferred equity associated with the generating assets to Calvert
Cliffs Nuclear Power Plant, Inc. and Constellation Power Source
Generation.
o The fossil fuel and nuclear fuel inventories, materials and supplies, and
certain purchased power contracts of BGE were also assumed by these
subsidiaries.
Effective July 1, 2000, BGE provides standard offer service to customers at
fixed rates over various time periods during the transition period for those
customers that do not choose an alternate supplier. In addition, the electric
fuel rate was discontinued effective July 1, 2000. Constellation Power Source
provides BGE with the energy and capacity required to meet its standard offer
service obligations for the first three years of the transition period. In
August 2001, BGE entered into contracts with CPS to supply 90% and Allegheny
Energy Supply Company, LLC to supply the remaining 10% of BGE's standard offer
service for the final three years (July 1, 2003 to June 30, 2006) of the
transition period. Over the transition period, the standard offer service rate
that BGE receives from its customers increases. This is offset by a
corresponding decrease in the competitive transition charge BGE receives.
Constellation Power Source obtains the energy and capacity to supply BGE's
standard offer service obligations from affiliates that own Calvert Cliffs
Nuclear Power Plant (Calvert Cliffs) and BGE's former fossil plants,
supplemented with energy and capacity purchased from the wholesale market as
necessary.
Other States
- ------------
Our domestic merchant energy business has $303.0 million invested in operating
power projects that sell 142 megawatts of electricity to Pacific Gas & Electric
(PGE) and to Southern California Edison (SCE) in California under power purchase
agreements as discussed in the California Power Purchase Agreements section in
the Notes to Consolidated Financial Statements on page 17. Our domestic 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. As a result, our current
portion of the amount due for unpaid power sales from these utilities is
approximately $50 million.
On April 6, 2001, California's largest utility, PGE, filed for
reorganization under Chapter 11 of the U.S. Bankruptcy Code. California's second
largest utility, SCE, has not met its obligations to pay for purchased power and
service its debt obligations, putting its creditors in a position to force SCE
into bankruptcy. The state of California has considered various legislative,
regulatory, financial, and other proposals to assist the utilities in purchasing
power and to reform the industry.
We also may be required by the Federal Energy Regulatory Commission (FERC)
to refund up to approximately $3 million in payments to the California
utilities. In addition, while it was operating, the California Power Exchange
and Independent System Operator, which provided the market for spot purchases of
electricity, required its power suppliers, including our power marketing
operation, to continue to sell power to the two utilities despite the fact that
they were not being paid.
The projects that we have an investment in recently entered into agreements
with SCE and PGE that provide for five-year fixed price payments averaging
$53.70 per megawatt-hour plus the stated capacity payments in the original SO4
contracts. These agreements also provide conditions for the payment of all past
due amounts plus interest, which the projects expect to collect in the next two
years.
We are currently constructing the 750 MW High Desert facility in California.
It is scheduled for completion in the summer of 2003. We signed a contract to
sell all of the plant's output to the California Department of Water Resources
on a unit contingent basis (i.e. if the output is not available because the
plant is not operating, there is no requirement to provide output from other
sources.) The contract has a term of eight years and three months.
To date, given the small size of our operations in California, these events
have not had a material impact on our financial results. However, we cannot
provide any assurance that the continuation of the market situation in
California will not have a materially adverse impact on our financial results,
or that any legislative, regulatory or other solution enacted in California will
permit us to recover any past losses or will not have a negative effect on
our business opportunities in California.
23
Gas Competition
- ---------------
Currently, no regulation exists for the wholesale price of natural gas as a
commodity, and the regulation of interstate transmission at the federal level
has been reduced. All BGE gas customers have the option to purchase gas from
other suppliers.
Market Risks
- ------------
Our earnings are exposed to various risks of the competitive marketplace,
including imbalances in supply and demand and changes in future commodity
prices, that may impact the financial results of our domestic merchant energy
business. For example, our earnings are exposed to the risks of the competitive
wholesale electricity market to the extent that our domestic merchant energy
business has to purchase energy and/or capacity to meet obligations to supply
power or meet other energy-related contractual arrangements at prices which may
approach or exceed the applicable fixed sales price obligations. If the price of
obtaining energy in the wholesale market exceeds the fixed sales price, our
earnings would be adversely affected.
In addition, many of our power generation facilities purchase fuel under
contracts or on the spot market. Fuel prices may also be volatile, and the price
that can be obtained from power sales may not change at the same rate as changes
in fuel costs.
To lower our financial exposure related to commodity price fluctuations, 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 as discussed further in the Risk Management and Hedging
Activities section of the Notes to Consolidated Financial Statements beginning
on page 18.
We are also affected by operational risk, that is, the risk that a
generating plant will not be available to produce energy when the energy is
required. Imbalances in demand and supply can occur not only because of plant
outages, but also because of transmission constraints, or extreme temperatures
(hot or cold) causing demand to exceed available supply.
We discuss our market risk further in our 2000 Annual Report on Form 10-K in
Item 7. Management Discussion and Analysis -- Market Risk.
Regulation by the Maryland PSC
- ------------------------------
In addition to electric restructuring which was discussed earlier, regulation by
the Maryland PSC influences BGE's businesses.
Under traditional rate regulation that continues after July 1, 2000 for
BGE's electric transmission and distribution, and gas businesses, the Maryland
PSC determines the rates we can charge our customers. Prior to July 1, 2000,
BGE's regulated electric rates consisted primarily of a "base rate" and a "fuel
rate." Effective July 1, 2000, BGE discontinued its electric fuel rate and
unbundled its rates to show separate components for delivery service,
competitive transition charges, standard offer services (generation),
transmission, universal service, and taxes. The rates for BGE's regulated gas
business continue to consist of a "base rate" and a "fuel rate."
Base Rate
- ---------
The base rate is the rate the Maryland PSC allows BGE to charge its customers
for the cost of providing them service, plus a profit. BGE has both an electric
base rate and a gas base rate. Higher electric base rates apply during the
summer when the demand for electricity is higher. Gas base rates are not
affected by seasonal changes.
BGE may ask the Maryland PSC to increase base rates from time to time. The
Maryland PSC historically has allowed BGE to increase base rates to recover
increased utility plant asset costs, plus a profit, beginning at the time of
replacement. Generally, rate increases improve our utility earnings because they
allow us to collect more revenue. However, rate increases are normally granted
based on historical data and those increases may not always keep pace with
increasing costs. Other parties may petition the Maryland PSC to decrease base
rates.
On November 17, 1999, BGE filed an application with the Maryland PSC to
increase its gas base rates. The Maryland PSC authorized a $6.4 million annual
increase in our gas base rates effective June 22, 2000.
As a result of the Restructuring Order, BGE's residential electric base
rates are frozen until 2006. Electric delivery service rates are frozen for a
four-year period 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.
Fuel Rate
- ---------
Through June 30, 2000, we charged our electric customers separately for the fuel
we used to generate electricity (nuclear fuel, coal, gas, or oil) and for the
net cost of purchases and sales of electricity. We charged the actual cost of
these items to the customer with no profit to us. If these fuel costs went up,
the Maryland PSC permitted us to increase the fuel rate.
Under the Restructuring Order, BGE's electric fuel rate was frozen until
July 1, 2000, at which time the fuel rate clause was discontinued. We deferred
the difference between our actual costs of fuel and energy and what we collected
from customers under the fuel rate through June 30, 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 ended October 2001. Effective July 1,
2000, earnings are affected by the changes in the cost of fuel and energy.
24
We charge our gas customers separately for the natural gas they purchase
from us. The price we charge for the natural gas is based on a market based
rates incentive mechanism approved by the Maryland PSC. We discuss market based
rates in more detail in the Gas Cost Adjustments section on page 33 and in Note
1 of our 2000 Annual Report on Form 10-K.
FERC Regulation--Regional Transmission Organizations
- ----------------------------------------------------
In December 1999, FERC issued Order 2000, amending its regulations under the
Federal Power Act to advance the formation of Regional Transmission
Organizations (RTOs). The regulations require that each public utility that
owns, operates, or controls facilities for the transmission of electric energy
in interstate commerce make certain filings with respect to forming and
participating in a RTO. FERC also identified the minimum characteristics and
functions that a transmission entity must satisfy in order to be considered a
RTO.
According to Order 2000, a public utility that is a member of an existing
transmission entity that has been approved by FERC as in conformance with the
Independent System Operator (ISO) principles set forth in the FERC Order No.
888, such as BGE, through its membership in PJM (Pennsylvania-New
Jersey-Maryland) Interconnection, was required to make a filing no later than
January 15, 2001. PJM and the joint transmission owners, including BGE, made the
filing on October 11, 2000. That filing explained the extent to which PJM met
the minimum characteristics and functions of a RTO and explained its plans to
conform to these characteristics and functions.
On July 12, 2001, FERC provisionally granted PJM RTO status and ordered it
to engage in mediation with the New York ISO and the New England ISO in regard
to creating a business plan to form one Northeast RTO, using PJM as a platform.
This mediation ended and the mediator issued his report to FERC on September 17,
2001. A FERC order regarding the mediator's report has not yet been issued. The
business plan makes no explicit provision for the continuation of PJM zonal
rates through 2004. Absent an order from the FERC, PJM must move to a uniform
transmission rate by December 31, 2002. A uniform rate could expose BGE to
higher transmission rates.
As a member of PJM, an existing RTO/ISO, BGE's RTO/ISO member status will
remain unchanged by Order 2000 and the July 12, 2001 order. However, BGE,
jointly with other PJM transmission owners, requested rehearing and
clarification from FERC on its July 12, 2001 order regarding certain incentive
rates, interconnection procedures and allocations of interconnection costs. FERC
has not yet issued an order on this request.
Also, we are appealing in court two requirements of Order 2000 whereby:
o we would be required to go through PJM to make a filing with FERC to
change our transmission rates, and
o we would be required to transfer operational control of our transmission
facilities to PJM.
The U.S. Supreme Court heard an appeal by others of FERC Order 888 in
October 2001. We cannot predict the outcome of this appeal or the impact on BGE
at this time.
Weather
- -------
Domestic Merchant Energy Business
- ---------------------------------
Weather conditions in the different regions of North America influence the
financial results of our domestic merchant energy business. Typically, demand
for electricity and its price are higher in the summer and the winter, when
weather is more extreme. However, all regions of North America typically do not
experience extreme weather conditions at the same time. Since the majority of
our generating plants currently are located in PJM, our financial results are
affected by weather conditions in this area.
Weather conditions also can affect the forward market price of energy
commodity and derivative contracts used by our power marketing operation that
are accounted for on a mark-to-market basis. To the extent that our power
marketing operation purchases and sells such contracts, our financial results
could be influenced by the impact that weather conditions have on the market
price of such contracts.
BGE
- ---
Weather affects the demand for electricity and gas for our regulated businesses.
Very hot summers and very cold winters increase demand. Mild weather reduces
demand. Residential sales for our regulated businesses are impacted more by
weather than commercial and industrial sales, which are mostly affected by
business needs for electricity and gas.
However, the Maryland PSC allows us to record a monthly adjustment to our
regulated gas business revenues to eliminate the effect of abnormal weather
patterns. We discuss this further in the Weather Normalization section on page
33.
25
We measure the weather's effect using "degree days." A degree day is the
difference between the average daily actual temperature and a baseline
temperature of 65 degrees. Cooling degree days result when the average daily
actual temperature exceeds the 65 degree baseline. Heating degree days result
when the average daily actual temperature is less than the baseline.
During the cooling season, hotter weather is measured by more cooling degree
days and results in greater demand for electricity to operate cooling systems.
During the heating season, colder weather is measured by more heating degree
days and results in greater demand for electricity and gas to operate heating
systems.
We show the number of degree days in the quarters and nine months
ended September 30, 2001 and 2000, and the percentage change in the number of
degree days between these periods in the following table:
Quarter Ended Nine Months Ended
September 30 September 30
2001 2000 2001 2000
- -------------------------------------------------------
Heating degree days 136 142 3,053 2,959
Percent change from
prior period (4.2)% 3.2%
Cooling degree days 495 445 756 714
Percent change from
prior period 11.2% 5.9%
Other Factors
- -------------
Other factors, aside from weather, impact the demand for electricity and gas in
our regulated businesses. These factors include the "number of customers" and
"usage per customer" during a given period. We use these terms later in our
discussions of regulated electric and gas operations. In those sections, we
discuss how these and other factors affected electric and gas sales during the
periods presented.
The number of customers in a given period is affected by new home and
apartment construction and by the number of businesses in our service territory.
Under the Restructuring Order, BGE's electric customers can become delivery
service customers only and can purchase their electricity from other sources. We
will collect a delivery service charge to recover the fixed costs for the
service we provide. The remaining electric customers will receive standard offer
service from BGE at the fixed rates provided by the Restructuring Order. Usage
per customer refers to all other items impacting customer sales that cannot be
measured separately. These factors include the strength of the economy in our
service territory. When the economy is healthy and expanding, customers tend to
consume more electricity and gas. Conversely, during an economic downtrend, our
customers tend to consume less electricity and gas.
26
Results of Operations for the Quarter and Nine Months Ended September 30, 2001
- ------------------------------------------------------------------------------
Compared with the Same Periods of 2000
- --------------------------------------
In this section, we discuss our earnings and the factors affecting them. We
begin with a general overview, then separately discuss earnings for our
operating segments. Changes in fixed charges and income taxes are discussed in
the aggregate for all segments in the Consolidated Nonoperating Income and
Expenses section on page 34.
Overview
Total Earnings Per Share of Common Stock
Quarter Ended Nine Months
Ended Ended
September 30, September 30,
2001 2000 2001 2000
- -----------------------------------------------------------
Earnings before
nonrecurring charges
included in operations:
Domestic merchant energy $ .89 $ .87 $1.50 $1.10
Regulated electric .17 .10 .46 .65
Regulated gas (.02) (.03) .18 .12
Other nonregulated (.04) .04 -- (.01)
- -----------------------------------------------------------
Total earnings per
share before
nonrecurring charges
included in
operations 1.00 .98 2.14 1.86
Nonrecurring charges
included in operations:
Deregulation
transition cost -- -- -- (.10)
TVSERP -- -- -- (.03)
- -----------------------------------------------------------
Earnings per share before
cumulative effect of
change in accounting
principle 1.00 .98 2.14 1.73
Cumulative effect of
change in accounting
principle, net of
income taxes -- -- .06 --
- -----------------------------------------------------------
Total earnings per share $1.00 $ .98 $2.20 $1.73
===========================================================
Earnings for the periods presented reflect a significant shift from the
regulated electric business to the domestic merchant energy business as a result
of the transfer of BGE's electric generation assets to nonregulated subsidiaries
on July 1, 2000 in accordance with the Restructuring Order. We discuss the
Restructuring Order in more detail in Current Issues - Electric Competition
section on page 22.
Quarter Ended September 30, 2001
- --------------------------------
Our total earnings for the quarter ended September 30, 2001 increased $.02 per
share compared to the same period of 2000 mostly because:
o our regulated electric business had higher earnings due to warmer summer
weather and lower expenses, and
o our domestic merchant energy business had higher earnings due to
favorable market price changes on open trading positions in our power
marketing operation.
These were partially offset by lower earnings from our financial investments
business due to declining equity values and the absence of gains on sales of
equity securities that occurred in 2000. In addition, we had lower earnings due
to a change in the method of accounting for our investment in Orion as discussed
in more detail in the Notes to Consolidated Financial Statements on page 19.
Nine Months Ended September 30, 2001
- ------------------------------------
Our total earnings for the nine months ended September 30, 2001 increased $.47
per share compared to the same period of 2000. Our total earnings increased
mostly because of the following:
o We recorded $75.0 million pre-tax, or approximately $.30 per share, of
amortization expense for the reduction of our generating plants
associated with the Restructuring Order in 2000 that had a negative
impact in that period.
o We recorded a nonrecurring expense of $15.0 million, after-tax, for
deregulation transition cost to Goldman Sachs incurred by our power
marketing business that had a negative impact in 2000.
o We recorded a nonrecurring expense of $4.2 million, after-tax, for BGE
employees that elected to participate in a Targeted Voluntary Special
Early Retirement Program (TVSERP) in 2000 that had a negative impact in
that period.
o We recorded an $8.5 million after-tax, or $.06 per share, gain for the
cumulative effect of adopting Statement of Financial Accounting Standard
(SFAS) No. 133, Accounting for Derivative Instruments and Hedging
Activities, as amended, in the first quarter of 2001.
o We had higher earnings from our regulated gas business.
These items were partially offset by $17.6 million pre-tax, or $.07 per
share, recorded in 2001 related to the impact of a 6.5% annual residential rate
reduction that was effective July 1, 2000.
Earnings per share contributions from all our business segments were
impacted by additional dilution resulting from the issuance of 13.2 million
shares of common stock between January 1, 2001 and the date of our report.
In the following sections, we discuss our earnings by business segment in
greater detail.
27
Domestic Merchant Energy Business
- ---------------------------------
Our domestic merchant energy business engages primarily in power marketing and
domestic power generation in North America. We describe this business in more
detail in our 2000 Annual Report on Form 10-K in Item 1. Business -- Domestic
Merchant Energy Business.
As discussed in the Current Issues -- Electric Competition section on page
22, our domestic merchant energy business was significantly impacted by the July
1, 2000 implementation of customer choice in Maryland. At that time, BGE's
generating assets became part of our nonregulated domestic merchant energy
business, and Constellation Power Source began selling to BGE the energy and
capacity required to meet its standard offer service obligations for the first
three years of the transition period. In August 2001, BGE entered into contracts
with CPS to supply 90% and Allegheny Energy Supply Company, LLC to supply the
remaining 10% of BGE's standard offer service for the final three years (July 1,
2003 to June 30, 2006) of the transition period.
Constellation Power Source obtains the energy and capacity to supply BGE's
standard offer service obligations from affiliates that own Calvert Cliffs and
BGE's former fossil plants, supplemented with energy and capacity purchased from
the wholesale energy market as necessary. Constellation Power Source also
manages our wholesale market price risk.
In addition, effective July 1, 2000, domestic merchant energy business
revenues include 90% of the competitive transition charges BGE collects from its
customers (CTC revenues) and the portion of BGE's revenues providing for nuclear
decommissioning costs.
Earnings
Quarter Ended Nine Months Ended
September 30, September 30,
2001 2000 2001 2000
- ------------------------------------------------------------
(In millions, except per share amounts)
Revenues $ 617.3 $499.4 $1,348.8 $ 673.1
Operating expenses 328.0 232.5 809.4 363.3
Depreciation and
amortization 42.9 38.6 122.4 41.9
Taxes other than income
taxes 10.7 13.1 33.5 13.2
- ------------------------------------------------------------
Income from operations $ 235.7 $215.2 $ 383.5 $ 254.7
============================================================
Net income $ 144.9 $129.9 $ 239.7 $ 150.0
============================================================
Total earnings per share
before nonrecurring
charges included in
operations $ .89 $ .87 $ 1.50 $ 1.10
Deregulation
transition
cost -- -- -- (.10)
- ------------------------------------------------------------
Earnings per share $ .89 $ .87 $ 1.50 $ 1.00
============================================================
Above amounts include intercompany transactions eliminated in our Consolidated
Financial Statements. The Information by Operating Segment section within the
Notes to Consolidated Financial Statements on page 13 provides a reconciliation
of operating results by segment to our Consolidated Financial Statements.
Revenues
- --------
During the quarter ended September 30, 2001, domestic merchant energy revenues
increased $117.9 million compared to the same period of 2000 mostly because of
higher revenues from our power marketing and domestic generation operations.
These were partially offset by the absence of approximately $8.0 million in CTC
lump sum payments that were received in 2000.
During the nine months ended September 30, 2001, domestic merchant energy
revenues increased $675.7 million compared to the same period of 2000 mostly
because of:
o a $547.9 million increase related to providing BGE the energy and
capacity required to meet its standard offer service obligation effective
July 1, 2000,
o an $84.1 million increase related to CTC and decommissioning revenues
included in the domestic merchant energy business effective July 1, 2000,
and
o higher revenues from our power marketing and domestic generation
operations.
We discuss the revenues for our power marketing and domestic generation
operations in the following sections.
Power Marketing
- ---------------
During the quarter and nine months ended September 30, 2001, power marketing
revenues increased compared to the same periods of 2000 mostly because of the
effect of favorable market price changes on open trading positions partially
offset by lower revenues from structured transactions.
Constellation Power Source uses the mark-to-market method of accounting for
its energy trading activities. We discuss the mark-to-market method of
accounting and Constellation Power Source's activities in more detail in Note 1
of our 2000 Annual Report on Form 10-K. As a result of the nature of its
operations and the use of mark-to-market accounting, Constellation Power
Source's revenues and earnings will fluctuate. We cannot predict these
fluctuations, but the effect on our revenues and earnings could be material. The
primary factors that cause these fluctuations are:
o the number and size of new transactions,
o the magnitude and volatility of changes in commodity prices and interest
rates, and
o the number and size of open commodity and derivative positions
Constellation Power Source holds or sells.
Constellation Power Source's management uses its best estimates to determine
the fair value of commodity and derivative positions it holds and sells. These
estimates consider various factors including closing exchange and
over-the-counter price quotations, time value, volatility factors, and credit
exposure. However, it is possible that future market prices could vary from
those used in recording assets and liabilities from power marketing and trading
activities, and such variations could be material.
28
Domestic Generation
- -------------------
During the quarter ended September 30, 2001, domestic generation revenues
increased compared to the same period of 2000 mostly because of revenues
associated with the new peaking facilities that commenced operations during this
summer, partially offset by lower revenues associated with the California power
purchase agreements discussed below.
During the nine months ended September 30, 2001, domestic generation
revenues increased compared to the same period of 2000 mostly because of
revenues associated with the new peaking facilities and a $9.5 million gain on
the sale of a project under development located in the PJM region recorded in
March 2001.
These were offset by a $13.3 million gain on the termination of an operating
arrangement and sale of certain subsidiaries of Constellation Operating Services
Inc. (COSI), a subsidiary of Constellation Power, Inc., to Orion Power Holdings
Inc. that occurred in April 2000. In addition, during the nine months ended
September 30, 2001, our domestic generation operation had lower revenues from
COSI due to the sale of these subsidiaries as well as lower revenues associated
with the California power purchase agreements. We discuss the California power
purchase agreements below.
California Power Purchase Agreements
- ------------------------------------
Our domestic generation operation has $303.0 million invested in 14 operating
projects that sell electricity in California to SCE and PGE under power purchase
agreements called "Interim Standard Offer No. 4 (SO4)" agreements.
Under these agreements, the electricity rates changed from fixed rates to
variable rates beginning in 1996. In 2000, the last four projects transitioned
to variable rates. During the quarter and nine months ended September 30, 2001,
revenues from these projects decreased compared to the same periods of 2000
because of lower power prices in California during the third quarter 2001. While
energy rates were higher during the first half of 2001, the higher rates were
offset by reserves established for our exposure in California during that
period.
As previously discussed in the Current Issues - Other States section on page
23, the projects recently entered into agreements with SCE and PGE that provide
for five-year fixed price payments averaging $53.70 per megawatt-hour plus the
stated capacity payments in the original SO4 contracts. We expect the revenues
from these projects to be lower in 2002 compared to 2001.
We also describe these projects and the transition process in the Notes to
Consolidated Financial Statements and Note 10 of our 2000 Annual Report on Form
10-K.
Operating Expenses
- ------------------
Domestic merchant energy operating expenses increased $95.5 million for the
quarter ended September 30, 2001 compared to the same period of 2000 mostly
because our power marketing operation recognized higher expenses on new
structured transactions and higher operating expenses associated with the growth
of this business. In addition, our domestic generation operation recognized
operating costs associated with the new peaking facilities that commenced
operations during this summer.
Domestic merchant energy operating expenses increased $446.1 million for the
nine months ended September 30, 2001 compared to the same period of 2000 mostly
because of the following:
o Increases in fuel costs of $206.4 million and operations and maintenance
costs of $194.7 million. These costs were associated with the generation
plants that were transferred from BGE effective July 1, 2000.
o The operating costs associated with the new peaking facilities.
o Higher operating expenses at our power marketing operation associated
with the growth of this business.
These increased costs were partially offset by lower transaction related
expenses on new structured transactions by our power marketing operation,
including the absence of a $24.0 million deregulation transition cost incurred
to Goldman Sachs in the second quarter of 2000 that had a negative impact in
that period. In addition, COSI had lower operating expenses related to the sale
of certain subsidiaries to Orion as previously discussed.
Operating expenses for the quarters and nine months ended September 30, 2001
and 2000 include fees at our power marketing operation earned by Goldman Sachs
that will not be incurred in the future due to the termination of the power
business services agreement discussed in the Recent Events section on page 21.
The Goldman Sachs fees were $28.9 million for the quarter and $48.9 million for
the nine months ended September 30, 2001.
In addition, coal prices have increased during this year and we expect to
incur additional costs in the future to operate our coal generating facilities
due to these higher prices. Based on current price levels, we expect the annual
increase in coal costs to be approximately $55 million in 2002.
In light of the events of September 11, 2001, we have taken additional
security measures at our nuclear facilities. While we anticipate continuing to
incur additional security related costs at our nuclear facilities, we do not
expect that these costs will be material. However, the Nuclear Regulatory
Commission (NRC) currently is evaluating additional security measures that may
be required at nuclear facilities. At this time, we cannot determine the impact
on our financial results of any additional security measures that may be
required by the NRC.
29
Depreciation and Amortization Expense
- -------------------------------------
Domestic merchant energy depreciation and amortization expense increased $4.3
million for the quarter ended September 30, 2001 compared to the same period of
2000 mostly due to the expenses associated with the new peaking facilities that
commenced operations during this summer.
Domestic merchant energy depreciation and amortization expense increased
$80.5 million for the nine months ended September 30, 2001 compared to the same
period of 2000 mostly because of expenses associated with the generation plants
that were transferred from BGE effective July 1, 2000, and with the new peaking
facilities.
Taxes Other than Income Taxes
- -----------------------------
Domestic merchant energy taxes other than income taxes were about the same for
the quarter ended September 30, 2001 compared to the same period of 2000.
Domestic merchant energy taxes other than income taxes increased $20.3 for
the nine months ended September 30, 2001 compared to the same period of 2000
mostly because of taxes other than income taxes associated with the generation
plants that were transferred from BGE effective July 1, 2000.
- --------------------------------------------------------------------------------
Regulated Electric Business
- ---------------------------
As previously discussed, our regulated electric business was significantly
impacted by the July 1, 2000 implementation of customer choice. These changes
include BGE's generating assets and related liabilities becoming part of our
nonregulated domestic merchant energy business on that date.
Earnings
Quarter Ended Nine Months Ended
September 30, September 30,
2001 2000 2001 2000
- ---------------------------------------------------------
(In millions, except per share amounts)
Electric revenues $634.6 $598.4 $1,624.4 $1,688.4
Electric fuel and
purchased energy 418.0 388.3 977.7 632.4
Operations and
maintenance 60.2 62.0 184.9 384.7
Depreciation and
amortization 43.7 52.0 130.5 276.7
Taxes other than
income taxes 36.0 30.5 107.0 121.0
- ---------------------------------------------------------
Income from
operations $ 76.7 $ 65.6 $ 224.3 $ 273.6
=========================================================
Net income $ 27.3 $ 15.4 $ 73.0 $ 93.2
=========================================================
Total earnings per
share before
nonrecurring
charges included
in operations: $ .17 $ .10 $ .46 $ .65
TVSERP -- -- -- (.03)
- ---------------------------------------------------------
Earnings per share $ .17 $ .10 $ .46 $ .62
=========================================================
Above amounts include intercompany transactions eliminated in our Consolidated
Financial Statements. The Information by Operating Segment section within the
Notes to Consolidated Financial Statements on page13 provides a reconciliation
of operating results by segment to our Consolidated Financial Statements.
Electric Revenues
- -----------------
The changes in electric revenues in 2001 compared to 2000 were caused by:
Quarter Nine Months
Ended Ended
September 30, September 30,
2001 vs. 2000 2001 vs. 2000
- ----------------------------------------------------
(In millions)
Electric system
sales volumes $ 9.2 $ 18.1
Rates 10.7 (73.6)
Fuel rate surcharge 15.4 42.7
- ---------------------------------------------------
Total change in
electric revenues
from electric system 35.3 (12.8)
sales
Interchange and
other sales -- (53.8)
Other 0.9 2.6
- ---------------------------------------------------
Total change in
electric revenues $ 36.2 $ (64.0)
===================================================
Electric System Sales Volumes
- -----------------------------
"Electric system sales volumes" are sales to customers in
our service territory at rates set by the Maryland PSC. As part of the
Restructuring Order, the rates received from customers under the standard offer
service increase over the transition period as discussed further in the Current
Issues--Electric Competition section beginning on page 22. These sales do not
include interchange sales and sales to others.
The percentage changes in our electric system sales volumes, by type of
customer, in 2001 compared to 2000 were:
Quarter Nine Months
Ended Ended
September 30, September 30,
2001 vs. 2000 2001 vs. 2000
- -----------------------------------------------------
Residential 7.8% 4.7%
Commercial 1.7 1.6
Industrial (1.0) (0.1)
During the quarter ended September 30, 2001, we sold more electricity to
residential customers compared to the same period of 2000 due to warmer weather,
higher usage per customer, and an increased number of customers. We sold about
the same amount of electricity to commercial and industrial customers.
30
During the nine months ended September 30, 2001, we sold more electricity
to residential customers compared to the same period of 2000 due to higher usage
per customer, an increased number of customers, and warmer summer weather. We
sold about the same amount of electricity to commercial and industrial
customers.
Rates
- -----
Prior to July 1, 2000, our rates primarily consisted of an electric base rate
and an electric fuel rate. Effective July 1, 2000, BGE discontinued its electric
fuel rate and unbundled its rates to show separate components for delivery
service, transition charges, standard offer services (generation), transmission,
universal service, and taxes. BGE's rates also were frozen in total except for
the implementation of a residential base rate reduction totaling approximately
$54 million annually. In addition, 90% of the CTC revenues BGE collects and the
portion of its revenues providing for decommissioning costs, are included in
revenues of the domestic merchant energy business effective July 1, 2000.
Rate revenues for the quarter ended September 30, 2001 increased compared to
the same period of 2000 due to the increase in the standard offer service rate
that BGE charges its customers. This is partially offset by a decrease in the
10% portion of the CTC rate received from customers that is retained by BGE.
Rate revenues for the nine months ended September 30, 2001 decreased
compared to the same period of 2000 mostly due to the decreases caused by:
o the 6.5% annual residential rate reduction of $17.6 million recorded
through June 30, 2001, and
o the $84.1 million for transfer of revenues to the domestic merchant
energy business discussed above.
These decreases were partially offset by the other net impacts of the rate
restructuring discussed above and the increase in the standard offer service
rate that BGE charges its customers.
Fuel Rate Surcharge
- -------------------
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 discuss this further in the Electric Fuel Rate
Clause section below.
Interchange and Other Sales
- ---------------------------
"Interchange and other sales" are sales in the PJM energy market and to others.
PJM is a RTO/ISO that also operates a regional power pool with members that
include many wholesale market participants, as well as BGE, and other utility
companies. Prior to the implementation of customer choice, BGE sold energy to
PJM members and to others after it had satisfied the demand for electricity in
its own system.
Effective July 1, 2000, BGE no longer engages in interchange sales and these
activities are included in our domestic merchant energy business which resulted
in a decrease in interchange and other sales for the nine months ended September
30, 2001 compared to the same period of 2000.
Electric Fuel and Purchased Energy Expenses
- -------------------------------------------
Quarter Nine Months
Ended Ended
September 30, September 30,
2001 2000 2001 2000
- ---------------------------------------------------------
(In millions)
Actual costs $402.9 $388.3 $935.8 $642.1
Net recovery
(deferral) of
costs under
electric fuel
rate clause 15.1 -- 41.9 (9.7)
- ---------------------------------------------------------
Total electric
fuel and
purchased
energy expenses $418.0 $388.3 $977.7 $632.4
=========================================================
Actual Costs
- ------------
As discussed in the Current Issues--Electric Competition section on page 22,
effective July 1, 2000, BGE transferred its generating assets to, and began
purchasing substantially all of the energy and capacity required to provide
electricity to standard offer service customers from, the domestic merchant
energy business.
Our actual costs of fuel and purchased energy for the quarter ended
September 30, 2001 compared to the same period of 2000 were higher mostly
because BGE purchased more energy from the domestic merchant energy business to
meet its increased system sales volumes. This was partially offset by a lower
price for the energy.
Our actual costs of fuel and purchased energy for the nine months period
ended September 30, 2001 compared to the period of 2000 increased mostly because
of the deregulation of electric generation. The higher amount paid for purchased
energy is offset by the absence of $206.4 million in fuel costs, and lower
operations and maintenance, depreciation, taxes, and other costs at BGE as a
result of no longer owning and operating the transferred electric generation
plants.
Prior to July 1, 2000, BGE's purchased fuel and energy costs only included
actual costs of fuel to generate electricity (nuclear fuel, coal, gas, or oil)
and electricity we bought from others.
Electric Fuel Rate Clause
- -------------------------
Prior to July 1, 2000, we deferred (included as an asset or liability on the
Consolidated Balance Sheets and excluded from the Consolidated Statements of
Income) the difference between our actual costs of fuel and energy and what we
collected from customers under the fuel rate in a given period. Effective July
1, 2000, the fuel rate clause was discontinued under the terms of the
Restructuring Order. 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.
31
Electric Operations and Maintenance Expenses
- --------------------------------------------
Regulated electric operations and maintenance expenses were about the same for
the quarter ended September 30, 2001 compared to the same period of 2000.
Regulated electric operations and maintenance expenses decreased $199.8
million for the nine months ended September 30, 2001 compared to the same period
of 2000 mostly because of the following:
o Effective July 1, 2000, costs of $194.7 million were no longer incurred
by this business segment. These costs were associated with the electric
generation assets that were transferred to the domestic merchant energy
business.
o BGE recognized expenses of $7.0 million for employees that elected to
participate in a Targeted Voluntary Special Early Retirement Program in
2000, that had a negative impact in that period.
Electric Depreciation and Amortization Expense
- ----------------------------------------------
Regulated electric depreciation and amortization expense decreased $8.3 million
for the quarter ended September 30, 2001 compared to the same period of 2000
mostly because of lower amortization expense associated with regulatory assets.
Regulated electric depreciation and amortization expense decreased $146.2
million for the nine months ended September 30, 2001 compared to the same period
of 2000 mostly because of:
o the absence of $75.0 million for the amortization expense recorded in
2000 associated with the $150 million reduction of our generating plants
provided for in the Restructuring Order, and
o $75.1 million of expenses associated with the transfer of the generation
assets to the domestic merchant energy business effective July 1, 2000.
These decreases were offset partially by more electric plant in service (as
our level of plant in service changes, the amount of depreciation and
amortization expense changes).
Electric Taxes Other Than Income Taxes
- --------------------------------------
Regulated electric taxes other than income taxes increased $5.5 million for the
quarter ended September 30, 2001 compared to the same period of 2000 mostly
because of higher gross receipts taxes associated with higher revenues and we
had less tax credits.
Regulated electric taxes other than income taxes decreased $14.0 million for
the nine months ended compared to the same period of 2000. This was mostly due
to the absence of taxes other than income taxes associated with the generation
assets that were transferred to the domestic merchant energy business effective
July 1, 2000 partially offset by fewer tax credits.
Regulated Gas Business
- ----------------------
Earnings
Quarter Ended Nine Months Ended
September 30, September 30,
2001 2000 2001 2000
- ------------------------------------------------------------
(In millions, except per share amounts)
Gas revenues $ 66.7 $ 90.1 $534.0 $377.8
Gas purchased for
resale 22.9 48.2 328.0 192.0
Operations and
maintenance 23.2 26.2 72.4 73.1
Depreciation and
amortization 9.8 11.3 36.3 35.5
Taxes other than
income taxes 7.2 5.0 25.6 25.0
- ------------------------------------------------------------
Income (Loss) from
operations $ 3.6 $ (0.6) $ 71.7 $ 52.2
============================================================
Net (loss) income $ (2.3) $ (4.6) $ 29.4 $ 18.1
============================================================
Earnings per share $ (.02) $ (.03) $ .18 $ .12
============================================================
Above amounts include intercompany transactions eliminated in our Consolidated
Financial Statements. The Information by Operating Segment section within the
Notes to Consolidated Financial Statements on page 13 provides a reconciliation
of operating results by segment to our Consolidated Financial Statements.
Earnings from the regulated gas business improved slightly during the quarter
ended September 30, 2001 compared to the same period of 2000, related to lower
costs. Earnings this quarter reflect the seasonal pattern of low summer volumes.
Earnings from the regulated gas business increased during the nine months
ended September 30, 2001 compared to the same period of 2000 mostly due to the
sharing mechanism under our gas cost adjustment clauses and the increase in our
base rates.
All BGE customers have the option to purchase gas from other suppliers. To
date, customer choice has not had a material effect on our, and BGE's, financial
results.
Gas Revenues
- ------------
The changes in gas revenues in 2001 compared to 2000 were caused by:
Quarter Nine Months
Ended Ended
September 30, September 30,
2001 vs. 2000 2001 vs. 2000
- --------------------------------------------------------
(In millions)
Gas system
sales volumes $ (0.9) $ 15.8
Base rates -- 3.3
Weather normalization 0.9 (5.0)
Gas cost adjustments (9.4) 106.9
- --------------------------------------------------------
Total change in gas
revenues from gas
system sales (9.4) 121.0
Off-system sales (13.8) 33.8
Other (0.2) 1.4
- --------------------------------------------------------
Total change in
gas revenues $ (23.4) $156.2
========================================================
32
Gas System Sales Volumes
- ------------------------
The percentage changes in our gas system sales volumes, by type of customer, in
2001 compared to 2000 were:
Quarter Ended Nine Months Ended
September 30, September 30,
2001 vs. 2000 2001 vs. 2000
- -----------------------------------------------------
Residential (5.7)% 6.6%
Commercial 43.2 11.9
Industrial (24.6) (26.5)
During the quarter ended September 30, 2001, we sold less gas to residential
customers compared to the same period of 2000 mostly due to lower usage per
customer partially offset by an increased number of customers. We sold more gas
to commercial customers mostly due to higher usage per customer. We sold less
gas to industrial customers mostly because of lower usage by Bethlehem Steel and
other industrial customers due to their lower business needs related to the
general downturn in the economy.
During the nine months ended September 30, 2001, we sold more gas to
residential customers compared to the same period of 2000 mostly due to colder
winter weather, an increased number of customers, and higher usage per customer.
We sold more gas to commercial customers mostly due to higher usage per customer
and colder winter weather. We sold less gas to industrial customers mostly
because of lower usage by Bethlehem Steel and other industrial customers due to
their switching to lower cost alternative fuel sources and lower business needs,
partially offset by an increased number of customers.
Base Rates
- ----------
Base rate revenues increased for the nine months ended September 30, 2001
compared to the same period of 2000 mostly because the Maryland PSC authorized a
$6.4 million annual increase in our base rates effective June 22, 2000.
Weather Normalization
- ---------------------
The Maryland PSC allows us to record a monthly adjustment to our gas revenues to
eliminate the effect of abnormal weather patterns on our gas system sales
volumes. This means our monthly gas revenues are based on weather that is
considered "normal" for the month and, therefore, are not affected by actual
weather conditions.
Gas Cost Adjustments
- --------------------
We charge our gas customers for the natural gas they purchase from us using gas
cost adjustment clauses set by the Maryland PSC as described in Note 1 of our
2000 Annual Report on Form 10-K. However, 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. During the quarter ended
September 30, 2001, the shareholders' portion increased slightly compared to the
same period of 2000.
During the nine months ended September 30, 2001, the shareholders' portion
increased $3.8 million compared to the same period of 2000.
Delivery service customers, including Bethlehem Steel, are not subject to
the gas cost adjustment clauses because we are not selling gas to them. We
charge these customers fees to recover the fixed costs for the transportation
service we provide. These fees are the same as the base rate charged for gas
sales and are included in gas system sales volumes.
During the quarter ended September 30, 2001, gas cost adjustment revenues
decreased compared to the same period of 2000 mostly because the gas we sold was
at a lower price.
During the nine months ended September 30, 2001, gas cost adjustment
revenues increased compared to the same period of 2000 mostly because we sold
more gas at a higher price to non-delivery service customers. In the first half
of 2001, the revenue increase reflects the significant increase in natural gas
prices.
Off-System Sales
- ----------------
Off-system gas sales are low-margin direct sales of gas to wholesale suppliers
of natural gas outside our service territory. Off-system gas sales, which occur
after we have satisfied our customers' demand, are not subject to gas cost
adjustments. The Maryland PSC approved an arrangement for part of the margin
from off-system sales to benefit customers (through reduced costs) and the
remainder to be retained by BGE (which benefits shareholders). Changes in
off-system sales do not significantly impact earnings.
During the quarter ended September 30, 2001, revenues from off-system gas
sales decreased compared to the same period of 2000 mostly because we sold less
gas off-system at a lower price.
During the nine months ended September 30, 2001, revenues from off-system
gas sales increased compared to the same period of 2000 mostly because the gas
we sold off-system was at a higher price partially offset by less gas sold. In
the first half of 2001, the revenue increase reflects the significant increase
in natural gas prices.
Gas Purchased For Resale Expenses
- ---------------------------------
Actual costs include the cost of gas purchased for resale to our customers and
for off-system sales. Actual costs do not include the cost of gas purchased by
delivery service customers.
During the quarter ended September 30, 2001, our gas costs decreased
compared to the same period of 2000 mostly because we bought gas at a lower
price. During the nine months ended September 30, 2001, our gas costs increased
compared to the same period of 2000 mostly because we bought more gas for both
system and off-system sales and all of the gas purchased was at a higher price.
Other Gas Operating Expenses
- ----------------------------
During the quarter and nine months ended September 30, 2001, other gas operating
expenses were about the same compared to the same periods of 2000.
33
Other Nonregulated Businesses
- -----------------------------
Earnings
Quarter Nine Months
Ended Ended
September 30, September 30,
2001 2000 2001 2000
- -------------------------------------------------------------
(In millions, except per share amounts)
Revenues $ 119.2 $ 174.1 $460.9 $ 491.1
Operating expenses 109.8 134.1 394.9 422.1
Depreciation
and amortization 6.5 5.7 19.3 16.6
Taxes other than income
taxes 1.3 1.1 3.5 3.0
- ------------------------------------------------------------
Income from operations $ 1.6 $ 33.2 $ 43.2 $ 49.4
============================================================
Net (loss) income before
cumulative effect of
change in accounting
principle $ (6.3) $ 6.8 $ 0.4 $ (2.1)
Cumulative effect of
change in accounting
principle -- -- 8.5 --
- ------------------------------------------------------------
Net (loss) income $ (6.3) $ 6.8 $ 8.9 $ (2.1)
============================================================
Earnings per share before
cumulative effect of
change in accounting
principle $ (.04) $ .04 $ -- $ (.01)
Cumulative effect of
change in accounting
principle -- -- .06 --
- ------------------------------------------------------------
Earnings per share $ (.04) $ .04$ .06 $ (.01)
============================================================
Above amounts include intercompany transactions eliminated in our Consolidated
Financial Statements. The Information by Operating Segment section within the
Notes to Consolidated Financial Statements on page 13 provides a reconciliation
of operating results by segment to our Consolidated Financial Statements.
During the quarter ended September 30, 2001, earnings from our other
nonregulated businesses decreased compared to the same period of 2000 mostly
because of lower earnings from our financial investments business due to
declining equity values and the absence of gains on sales of equity securities
that occurred in 2000. In addition, we had lower earnings due to a change in the
method of accounting for our investment in Orion as discussed in more detail in
the Notes to Consolidated Financial Statements on page 19.
During the nine months ended September 30, 2001, earnings from our other
nonregulated businesses increased compared to the same period of 2000 mostly
because:
o we recorded a $9.0 million after-tax gain on the sale of one million
shares of the Orion investment, and
o we recorded an $8.5 million after-tax gain for the cumulative effect of
adopting SFAS No. 133 in the first quarter of 2001.
These increases were partially offset by lower earnings from our financial
investments business as discussed above.
Most of Constellation Real Estate Group's real estate and senior-living
projects are in the Baltimore-Washington corridor. The area has had a surplus of
available land in recent years and as a result these projects have been
economically hurt.
Constellation Real Estate's projects have continued to incur carrying costs
and depreciation over the years. Additionally, this operation has been charging
interest payments to expense rather than capitalizing them for some undeveloped
land where development activities have stopped. These carrying costs,
depreciation, and interest expenses have decreased earnings and are expected to
continue to do so.
Cash flow from real estate and senior-living operations has not been enough
to make the monthly loan payments on some of these projects. Cash shortfalls
have been covered by cash obtained from the cash flows of, or additional
borrowings by, other nonregulated subsidiaries.
We consider market demand, interest rates, the availability of financing,
competing demands for capital, and the strength of the economy in general when
making decisions about our real estate and senior-living projects. If we were to
decide to sell our projects, we could have write-downs. In addition, if we were
to sell our projects in the current market, we would have losses which could be
material, although the amount of the losses is hard to predict. Depending on
market conditions, we could also have material losses on any future sales.
Our current real estate and senior-living strategy is to hold each project
until we can realize a reasonable value for it. Under accounting rules, we are
required to write down the value of a project to market value in either of two
cases. The first is if we change our intent about a project from an intent to
hold to an intent to sell and the market value of that project is below book
value. The second is if the expected cash flow from the project is less than the
investment in the project.
Consolidated Nonoperating Income and Expenses
- ---------------------------------------------
Fixed Charges
- -------------
During the quarter ended September 30, 2001, total fixed charges decreased
compared to the same period of 2000 mostly because of lower interest rates.
During the nine months ended September 30, 2001, total fixed charges
decreased compared to the same period of 2000 mostly because of lower interest
rates and increased capitalized interest associated with our construction of new
generating facilities. These decreases were offset partially by a higher average
level of debt outstanding.
Income Taxes
- ------------
During the quarter ended September 30, 2001, our total income taxes increased
slightly compared to the same period of 2000 mostly because we had higher
taxable income from our domestic merchant energy business and the utility
business partially offset by lower taxable income from the other nonregulated
businesses.
During the nine months ended September 30, 2001, our total income taxes
increased compared to the same period of 2000 mostly because we had higher
taxable income from our domestic merchant energy business partially offset by
lower taxable income from the utility business.
34
Financial Condition
- -------------------
Cash Flows
- ----------
Nine Months
Ended
September 30,
2001 2000
- -----------------------------------------------------
(In millions)
Cash provided by (used in):
Operating Activities $ 644.8 $ 588.8
Investing Activities (909.7) (728.4)
Financing Activities 146.2 97.3
During the nine months ended September 30, 2001, we generated more cash from
operations compared to the same period in 2000 mostly because of changes in
working capital requirements.
During the nine months ended September 30, 2001, we used more cash for
investing activities compared to the same period in 2000 mostly due to an
increase in investments in new generation facilities, offset in part by the
sales of certain investments.
During the nine months ended September 30, 2001, we had more cash from
financing activities compared to the same period of 2000 mostly because we
issued more common stock and long-term debt. We also decreased our payment of
dividends because we changed our dividend policy effective April 1, 2001,
reducing our dividend to $.12 per quarter. This was partially offset by the
repayment of long-term debt.
Security Ratings
- ----------------
Independent credit-rating agencies rate Constellation Energy and BGE's
fixed-income securities. The ratings indicate the agencies' assessment of each
company's ability to pay interest, distributions, dividends, and principal on
these securities. These ratings affect how much it will cost each company to
sell these securities. The better the rating, the lower the cost of the
securities to each company when they sell them. Constellation Energy and BGE's
securities ratings at the date of this report are:
Standard Moody's
& Poors Investors Fitch
Rating Group Service IBCA
- ---------------------------------------------------------
Constellation Energy
Unsecured Debt A- A3 A-
BGE
Mortgage Bonds AA- A1 A+
Unsecured Debt A A2 A
Trust Originated
Preferred Securities
and Preference Stock A- Baa1 A-
Recently, Moody's Investors Service placed Constellation Energy under review
for possible downgrade and confirmed the ratings of BGE. Constellation Energy
remained on credit watch negative with Standard & Poors, while BGE was placed on
credit watch negative. Fitch IBCA reaffirmed ratings of both Constellation
Energy and BGE with stable outlooks.
- -------------------------------------------------------------------------------
Capital Resources
- -----------------
Our business requires a great deal of capital. Our estimated annual amounts for
the years 2001 and 2002, are shown in the table on page 36.
We will continue to have cash requirements for:
o working capital needs including the payments of interest, distributions,
and dividends,
o capital expenditures, and
o the retirement of debt and redemption of preference stock.
Capital requirements for 2001 and 2002 include estimates of funding for
existing and anticipated projects. We continuously review and modify those
estimates.
Actual requirements may vary from the estimates included in the table on page
36 because of a number of factors including:
o regulation, legislation, and competition,
o BGE load requirements,
o environmental protection standards,
o the type and number of projects selected for construction or acquisition,
o the effect of market conditions on those projects,
o the cost and availability of capital, and
o the availability of cash from operations.
Our estimates are also subject to additional factors. Please see the Forward
Looking Statements section on page 40.
35
Calendar Year Estimates
2001 2002
- --------------------------------------------------------------------------------------------
(In millions)
Nonregulated Capital Requirements:
Investment requirements:
Domestic merchant energy $1,345 $ 523
Other 42 67
- --------------------------------------------------------------------------------------------
Total investment requirements 1,387 590
Retirement of long-term debt 1,114 687
- --------------------------------------------------------------------------------------------
Total nonregulated capital requirements 2,501 1,277
Utility Capital Requirements:
Construction expenditures:
Regulated electric 162 156
Regulated gas 51 49
Common 26 25
- --------------------------------------------------------------------------------------------
Total capital expenditures 239 230
Retirement of long-term debt and redemption of
preference stock 394 520
- --------------------------------------------------------------------------------------------
Total utility capital requirements 633 750
- --------------------------------------------------------------------------------------------
Total capital requirements $3,134 $2,027
============================================================================================
Capital Requirements
- --------------------
Domestic Merchant Energy Business
- ---------------------------------
Our domestic merchant energy business will require additional funding for
growing its power marketing operation and developing and acquiring power
projects.
Our domestic merchant energy business capital requirements include one-half
of the total purchase price for the Nine Mile Point plant that we financed in
2001. Capital requirements for 2002 include the principal payments on
the sellers-provided financing for the remaining portion of the purchase price
and on-going capital requirements relating to the Nine Mile Point plant.
Also included are the construction of 1,100 megawatts of peaking capacity in
the Mid-Atlantic and Mid-West regions that commenced operations in the summer of
2001 and approximately 3,000 megawatts of natural gas-fired peaking and combined
cycle production facilities in various regions of North America under
construction and several projects in development. The above table does not
include the financing for the High Desert project in California, which is an
operating lease.
Our domestic merchant energy business investment requirements also include
construction expenditures for improvements to generating plants and costs for
replacing the steam generators at Calvert Cliffs.
In March 2000, we received a license extension from the NRC that extends
Calvert Cliffs' operating licenses to 2034 for Unit 1 and 2036 for Unit 2. If we
do not replace the steam generators, we will not be able to operate these units
through our operating license periods. We expect the steam generator replacement
to occur during the 2002 refueling outage for Unit 1 and during the 2003
refueling outage for Unit 2. We estimate these Calvert Cliffs' costs to be:
o $ 61 million in 2001,
o $ 88 million in 2002, and
o $ 60 million in 2003.
Additionally, our estimates of future electric generation construction
expenditures include the costs of complying with Environmental Protection Agency
(EPA), Maryland and Pennsylvania nitrogen oxides emissions (NOx) reduction
regulations as follows:
o $ 86 million in 2001,
o $ 70 million in 2002, and
o $ 16 million in 2003.
We discuss the NOx regulations and timing of expenditures in the
Environmental Matters section of the Notes to Consolidated Financial Statements
on page 15.
Regulated Electric and Gas
- --------------------------
Regulated electric and gas construction expenditures primarily include new
business construction needs and improvements to existing facilities.
36
Funding for Capital Requirements
- --------------------------------
In June 2001, Constellation Energy arranged two revolving credit facilities
that totaled $2.9 billion as discussed in the Financing Activity section of the
Notes to Consolidated Financial Statements on page 14.
Domestic Merchant Energy Business
- ---------------------------------
Funding for the expansion of our domestic merchant energy business is expected
from internally generated funds, commercial paper, long-term debt, equity,
leases, and other financing instruments issued by Constellation Energy and its
subsidiaries. Specifically related to the Nine Mile Point acquisition,
approximately one-half of the purchase price, or $380 million, was paid in
November 2001, 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%. We closed the
transaction using existing credit facilities. Payments on the note over the five
years are expected to come from internally generated funds. In addition, we also
used existing credit facilities to pay Goldman Sachs a total of $355 million.
This represented $196 million to terminate the power business services agreement
with our power marketing operation and $159 million previously recognized as a
payable for services rendered.
Longer term, we expect to fund our growth and operating objectives with a
mixture of debt and equity with an overall goal of maintaining an investment
grade credit profile.
Constellation Energy has a commercial paper program where it can issue
short-term notes to fund its nonregulated businesses. To support its commercial
paper program, Constellation Energy maintains three revolving credit agreements
totaling $3.1 billion, of which two facilities can also issue letters of credit.
We entered into two of these agreements during June 2001 as discussed above and
in the Financing Activity section of the Notes to Consolidated Financial
Statements on page 14. We expect to refinance the $2.5 billion facility during
the first half of 2002 with long-term debt. In addition, Constellation Energy
has access to interim lines of credit as required from time to time to support
its outstanding commercial paper.
BGE
- ---
Funding for utility capital expenditures is expected from internally generated
funds, commercial paper issuances, available capacity under credit facilities,
the issuance of long-term debt, trust securities, or preference stock, and/or
from time to time equity contributions from Constellation Energy.
BGE has FERC authority to issue up to $700 million of short-term borrowings,
including commercial paper. In addition, BGE maintains $218 million in annual
committed bank lines of credit and has $25 million in bank revolving credit
agreements to support the commercial paper program. BGE also has access to
interim lines of credit as required from time to time to support its outstanding
commercial paper.
During 2001 and 2002, we expect our regulated utility business to provide at
least 140% of the cash needed to meet the capital requirements for its
operations, excluding cash needed to retire debt.
Other Nonregulated Businesses
- -----------------------------
BGE Home Products & Services could fund capital requirements through sales of
receivables. ComfortLink has a revolving credit agreement totaling $50 million
to provide liquidity for short-term financial needs.
If we can get a reasonable value for our real estate projects, senior-living
facilities, remaining Latin American operations, and other investments,
additional cash may be obtained by selling them. Our ability to sell or
liquidate assets will depend on market conditions, and we cannot give assurances
that these sales or liquidations could be made. We discuss the real estate and
senior-living facilities operation and market conditions in the Other
Nonregulated Businesses section beginning on page 34.
- --------------------------------------------------------------------------------
Other Matters
- -------------
Environmental Matters
- ---------------------
We are subject to federal, state, and local laws and regulations that work to
improve or maintain the quality of the environment. If certain substances were
disposed of, or released at any of our properties, whether currently operating
or not, these laws and regulations require us to remove or remedy the effect on
the environment. This includes Environmental Protection Agency Superfund sites.
You will find details of our environmental matters in the Environmental Matters
section of the Notes to Consolidated Financial Statements beginning on page 15
and in our 2000 Annual Report on Form 10-K in Item 1. Business - Environmental
Matters. These details include financial information. Some of the information is
about costs that may be material.
Accounting Standards Adopted and Issued
- ---------------------------------------
We discuss recently adopted and issued accounting standards in the Accounting
Standard Adopted and Accounting Standards Issued sections of the Notes to
Consolidated Financial Statements beginning on page 17.
37
Item 3. Quantitative and Qualitative Disclosures About Market Risk
- ------------------------------------------------------------------
We discuss the following information related to our market risk:
o risk associated with the purchase and sale of energy in a deregulated
environment as discussed in the Current Issues - Electric Competition
section of Management's Discussion and Analysis on page 22,
o financing activities, accounting standard adopted, and risk management
and hedging activities in the Notes to Consolidated Financial Statements
beginning on page 14, and
o activities of our power marketing business in the Domestic Merchant
Energy Business section of Management's Discussion and Analysis beginning
on page 28.
- --------------------------------------------------------------------------------
PART II.
- --------
OTHER INFORMATION
- -----------------
Item 1. Legal Proceedings
- ------- -----------------
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.
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.
Moore v. Constellation Energy Group - This action was filed on October 23,
2000 in the U.S. District Court for the District of Maryland by an employee
alleging employment discrimination. Besides Constellation Energy, BGE and
Constellation Holdings, Inc. were also named defendants. The Equal Employment
Opportunity Commission previously concluded that it was unable to establish a
violation of law. The plaintiff sought, among other things, unspecified monetary
damages and back pay. The court dismissed the case in 2001.
Asbestos
- --------
Since 1993, we have been involved in several actions concerning asbestos. The
actions are based upon the theory of "premises liability," alleging that we 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. We
described these claims in BGE's Report on Form 8-K filed August 20, 1993. We are
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 since the summer of
1993. We do not know the specific facts necessary to estimate our potential
liability for these claims. The specific facts we do not know include:
o the identity of our 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 have been resolved for amounts that were not
significant.
The second type is claims by one manufacturer -- Pittsburgh Corning Corp.
(PCC) -- against us and approximately eight others, as third-party defendants.
On April 17, 2000, PCC declared bankruptcy and we do not expect PCC to prosecute
these claims.
38
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 payments by BGE. We do
not know the specific facts necessary to estimate our potential liability for
these claims. The specific facts we do not know include:
o the identity of our facilities containing asbestos manufactured by the
manufacturer,
o the relationship (if any) of each of the individual plaintiffs to us,
o the settlement amounts for any individual plaintiffs who are shown to
have had a relationship to us, and
o the dates on which/places at which the exposure allegedly occurred.
Until the relevant facts for both types of claims are determined, we are
unable to estimate what our 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, our potential liability could be
material.
Restructuring Order
- -------------------
In early December 1999, the Mid-Atlantic Power Supply Association (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.
Asset Transfer Order
- --------------------
On July 6, 2000, 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.
39
Item 5. Other Information
- ------- -----------------
Forward Looking Statements
- --------------------------
We make statements in this report that are considered forward looking statements
within the meaning of the Securities Exchange Act of 1934. Sometimes these
statements will contain words such as "believes," "expects," "intends," "plans,"
and other similar words. These statements are not guarantees of our future
performance and are subject to risks, uncertainties and other important factors
that could cause our actual performance or achievements to be materially
different from those we project. These risks, uncertainties, and factors
include, but are not limited to:
o The timing and extent of changes in commodity prices for energy including
coal, natural gas, oil, and electricity.
o The timing and extent of deregulation of, and competition in, the energy
markets in North America, and the rules and regulations adopted on a
transitional basis in those markets.
o The conditions of the capital markets generally, which are affected by
interest rates and general economic conditions, as well as Constellation
Energy and BGE's ability to maintain their current debt ratings.
o The effectiveness of Constellation Energy's risk management policies and
procedures and the ability of our counterparties to satisfy their
financial commitments.
o The liquidity and competitiveness of wholesale trading markets for energy
commodities.
o Operational factors affecting the start-up or ongoing commercial
operations of our generating facilities and BGE's transmission and
distribution facilities, including catastrophic weather related damages,
unscheduled outages or repairs, unanticipated changes in fuel costs or
availability, unavailability of gas transportation or electric
transmission services, workforce issues, terrorism and other events
beyond our control.
o The inability of BGE to recover all its costs associated with providing
electric retail customers service during the electric rate freeze period.
o The effect of weather and general economic and business conditions on
energy supply, demand and prices. Regulatory or legislative developments
that affect demand for energy, or increase costs, including costs related
to nuclear power plants, safety or environmental compliance.
o Cost and other effect of legal and administrative proceedings that may
not be covered by insurance, including environmental liabilities or the
outcome of pending appeals regarding the Maryland PSC's orders on
electric deregulation and the transfer of BGE's generation assets to
affiliates.
o Operation of our generation assets in a deregulated market without the
benefit of a fuel rate adjustment clause.
Given these uncertainties, you should not place undue reliance on these
forward looking statements. Please see the other sections of this report and our
other periodic reports filed with the SEC for more information on these factors.
These forward looking statements represent our estimates and assumptions only as
of the date of this report.
Changes may occur after that date, and neither Constellation Energy nor BGE
assume responsibility to update these forward looking statements.
40
Item 6. Exhibits and Reports on Form 8-K
- ----------------------------------------
(a) Exhibit No. 10(a) Full Requirements Service Agreement Between Baltimore Gas and
Electric Company and Constellation Power Source, Inc. (portions of
this exhibit have been omitted pursuant to a request for confidential
treatment).
Exhibit No. 10(b) Full Requirements Service Agreement Between Baltimore Gas and
Electric Company and Allegheny Energy Supply Company, L.L.C.
(portions of this exhibit have been omitted pursuant to a request for
confidential treatment).
Exhibit No. 12(a) Constellation Energy Group, Inc. Computation of Ratio of Earnings to
Fixed Charges.
Exhibit No. 12(b) Baltimore Gas and Electric Company Computation of Ratio of Earnings
to Fixed Charges and Computation of Ratio of Earnings to Combined
Fixed Charges and Preferred and Preference Dividend Requirements.
(b) Reports on Form 8-K for the quarter ended September 30, 2001:
Date Filed Items Reported
---------- --------------
August 24, 2001 Item 5. Other Events
Item 7. Financial Statements and Exhibits
41
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, each
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
CONSTELLATION ENERGY GROUP, INC.
-----------------------------------------
(Registrant)
Date: November 14, 2001 /s/ E. Follin Smith
----------------- ------------------------------------------
E. Follin Smith, Senior Vice President on behalf
of Constellation Energy Group, Inc. and
as Principal Financial Officer
BALTIMORE GAS AND ELECTRIC COMPANY
------------------------------------------
(Registrant)
Date: November 14, 2001 /s/ Thomas F. Brady
----------------- -----------------------------------------------
Thomas F. Brady, on behalf of Baltimore Gas and
Electric Company as Principal Financial Officer
42