-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, UTSk9nGg6NaKY9g4++1YdloK/+DSLYvQhvPYR++bBlw6tMNzNFi4HX0qE8361YLl JKfed5vvKLal9v6KoaDTCg== 0001004440-01-500064.txt : 20010814 0001004440-01-500064.hdr.sgml : 20010814 ACCESSION NUMBER: 0001004440-01-500064 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 3 CONFORMED PERIOD OF REPORT: 20010630 FILED AS OF DATE: 20010813 FILER: COMPANY DATA: COMPANY CONFORMED NAME: BALTIMORE GAS & ELECTRIC CO CENTRAL INDEX KEY: 0000009466 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC & OTHER SERVICES COMBINED [4931] IRS NUMBER: 520280210 STATE OF INCORPORATION: MD FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-Q SEC ACT: 1934 Act SEC FILE NUMBER: 001-01910 FILM NUMBER: 1706796 BUSINESS ADDRESS: STREET 1: 39 WEST LEXINGTON STREET CITY: BALTIMORE STATE: MD ZIP: 21201 BUSINESS PHONE: 4107833624 MAIL ADDRESS: STREET 1: 39 WEST LEXINGTON STREET CITY: BALTIMORE STATE: MD ZIP: 21201 FILER: COMPANY DATA: COMPANY CONFORMED NAME: CONSTELLATION ENERGY GROUP INC CENTRAL INDEX KEY: 0001004440 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] IRS NUMBER: 521964611 STATE OF INCORPORATION: MD FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-Q SEC ACT: 1934 Act SEC FILE NUMBER: 000-25931 FILM NUMBER: 1706797 BUSINESS ADDRESS: STREET 1: 250 W PRATT STREET CITY: BALTIMORE STATE: MD ZIP: 21201 BUSINESS PHONE: 4102345685 MAIL ADDRESS: STREET 1: 250 W PRATT STREET CITY: BALTIMORE STATE: MD ZIP: 21201 FORMER COMPANY: FORMER CONFORMED NAME: CONSTELLATION ENERGY CORP DATE OF NAME CHANGE: 19951220 FORMER COMPANY: FORMER CONFORMED NAME: RH ACQUISITION CORP DATE OF NAME CHANGE: 19951205 10-Q 1 f2q01.txt SECOND QUARTER FORM 10Q 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 JUNE 30, 2001 Commission File Exact name of registrant IRS Employer Number as 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 ------------------------- ---------------------------- ----- (Address of principal executive offices) (Zip Code) 410-234-5000 (Registrants' telephone number, including area code) NOT APPLICABLE ------------------------------------------------------------------------------ (Former name, former address and former fiscal year, if changed since last report) Indicate by check mark whether the 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 ---------- ------------ Common Stock, without par value 163,707,950 shares outstanding of Constellation Energy Group, Inc. on July 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........................................................................... 18 Strategy............................................................................... 19 Current Issues......................................................................... 20 Results of Operations.................................................................. 24 Financial Condition.................................................................... 31 Capital Resources...................................................................... 32 Other Matters.......................................................................... 34 Item 3 -- Quantitative and Qualitative Disclosures About Market Risk............................. 34 Part II -- Other Information Item 1 -- Legal Proceedings...................................................................... 35 Item 4 -- Submission of Matters to a Vote of Security Holders.................................... 36 Item 5 -- Other Information...................................................................... 37 Item 6 -- Exhibits and Reports on Form 8-K....................................................... 37 Signature........................................................................................ 38
2 CONSTELLATION ENERGY GROUP, INC. AND SUBSIDIARIES PART 1 - FINANCIAL INFORMATION Item 1 - Financial Statements Consolidated Statements of Income (Unaudited)
Three Months Ended Six Months Ended June 30, June 30, 2001 2000 2001 2000 - ------------------------------------------------------------------------------------------------------------------ Revenues (In millions, except per share amounts) Nonregulated revenues $235.0 $209.7 $ 536.5 $ 484.8 Regulated electric revenues 497.4 565.3 989.6 1,089.7 Regulated gas revenues 109.6 91.6 461.8 286.1 - ------------------------------------------------------------------------------------------------------------------ Total revenues 842.0 866.6 1,987.9 1,860.6 Expenses Operating expenses 514.7 552.8 1,264.8 1,168.6 Depreciation and amortization 102.0 130.6 205.6 263.1 Taxes other than income taxes 55.5 51.1 113.9 112.3 - ------------------------------------------------------------------------------------------------------------------ Total expenses 672.2 734.5 1,584.3 1,544.0 - ------------------------------------------------------------------------------------------------------------------ Income from Operations 169.8 132.1 403.6 316.6 Other Income 5.4 2.8 5.4 6.0 - ------------------------------------------------------------------------------------------------------------------ Income Before Fixed Charges and Income Taxes 175.2 134.9 409.0 322.6 Fixed Charges Interest expense (net) 53.7 65.1 116.4 125.4 BGE preference stock dividends 3.3 3.3 6.6 6.6 - ------------------------------------------------------------------------------------------------------------------ Total fixed charges 57.0 68.4 123.0 132.0 - ------------------------------------------------------------------------------------------------------------------ Income Before Income Taxes 118.2 66.5 286.0 190.6 Income Taxes Current 36.5 45.6 112.4 106.8 Deferred 8.1 (16.6) (1.2) (23.7) Investment tax credit adjustments (2.0) (2.1) (4.1) (4.2) - ------------------------------------------------------------------------------------------------------------------ Total income taxes 42.6 26.9 107.1 78.9 - ------------------------------------------------------------------------------------------------------------------ Income Before Cumulative Effect of Change in Accounting Principle $ 75.6 $ 39.6 $ 178.9 $ 111.7 Cumulative Effect of Change in Accounting Principle, Net of Income Taxes of $5.6 -- -- 8.5 -- - ------------------------------------------------------------------------------------------------------------------ Net Income $ 75.6 $ 39.6 $ 187.4 $ 111.7 - ------------------------------------------------------------------------------------------------------------------ Earnings Applicable to Common Stock $ 75.6 $ 39.6 $ 187.4 $ 111.7 ================================================================================================================== Average Shares of Common Stock Outstanding 163.7 149.7 157.8 149.6 Earnings Per Common Share and Earnings Per Common Share - Assuming Dilution Before Cumulative Effect of Change in Accounting Principle $ 0.46 $ 0.26 $ 1.13 $ 0.75 Cumulative Effect of Change in Accounting Principle -- -- .06 -- - ------------------------------------------------------------------------------------------------------------------ Earnings Per Common Share and Earnings Per Common Share - Assuming Dilution $ 0.46 $ 0.26 $ 1.19 $ 0.75 Dividends Declared Per Common Share $ 0.12 $ 0.42 $ 0.24 $ 0.84
Consolidated Statements of Comprehensive Income (Unaudited) Three Months Ended Six Months Ended June 30, June 30, 2001 2000 2001 2000 - ------------------------------------------------------------------------------------------------------------------ (In millions) Net Income $ 75.6 $ 39.6 $187.4 $111.7 Other comprehensive income, net of taxes 193.6 11.1 179.3 24.1 - ------------------------------------------------------------------------------------------------------------------ Comprehensive Income Before Cumulative Effect of Change in Accounting Principle 269.2 50.7 366.7 135.8 Cumulative Effect of Change in Accounting Principle, Net of Income Taxes of $22.6 -- -- (35.5) -- - ------------------------------------------------------------------------------------------------------------------ Comprehensive Income $269.2 $ 50.7 $331.2 $135.8 ==================================================================================================================
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
June 30, December 31, 2001* 2000 - ---------------------------------------------------------------------------------------------------------------------- (In millions) Assets Current Assets Cash and cash equivalents $ 111.8 $ 182.7 Accounts receivable (net of allowance for uncollectibles of $22.5 and $21.3 respectively) 683.8 738.5 Trading securities 201.9 189.3 Assets from energy trading activities 3,005.6 2,793.0 Fuel stocks 91.6 78.2 Materials and supplies 159.6 151.3 Prepaid taxes other than income taxes 4.1 73.5 Other 48.6 32.7 - ---------------------------------------------------------------------------------------------------------------------- Total current assets 4,307.0 4,239.2 - ---------------------------------------------------------------------------------------------------------------------- Investments and Other Assets Real estate projects and investments 287.3 290.3 Investments in power projects 517.6 517.5 Financial investments 98.9 161.0 Nuclear decommissioning trust fund 241.5 228.7 Net pension asset 107.3 93.2 Investment in Orion Power Holdings, Inc. 406.2 192.0 Other 131.2 123.0 - ---------------------------------------------------------------------------------------------------------------------- Total investments and other assets 1,790.0 1,605.7 - ---------------------------------------------------------------------------------------------------------------------- Property, Plant and Equipment Regulated property, plant and equipment 4,873.8 4,860.1 Nonregulated generation property, plant and equipment 5,755.7 5,279.9 Other nonregulated property, plant and equipment 197.0 173.8 Nuclear fuel (net of amortization) 108.5 128.3 Accumulated depreciation (3,860.6) (3,798.1) - ---------------------------------------------------------------------------------------------------------------------- Net property, plant and equipment 7,074.4 6,644.0 - ---------------------------------------------------------------------------------------------------------------------- Deferred Charges Regulatory assets (net) 444.6 514.9 Other 120.6 117.3 - ---------------------------------------------------------------------------------------------------------------------- Total deferred charges 565.2 632.2 - ---------------------------------------------------------------------------------------------------------------------- Total Assets $13,736.6 $13,121.1 ======================================================================================================================
* 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
June 30, December 31, 2001* 2000 - ---------------------------------------------------------------------------------------------------------------------- (In millions) Liabilities and Capitalization Current Liabilities Short-term borrowings $ 310.2 $ 243.6 Current portions of long-term debt 1,215.8 906.6 Accounts payable 640.0 695.9 Liabilities from energy trading activities 2,428.1 2,323.3 Dividends declared 23.0 66.5 Other 196.0 250.8 - ---------------------------------------------------------------------------------------------------------------------- Total current liabilities 4,813.1 4,486.7 - ---------------------------------------------------------------------------------------------------------------------- Deferred Credits and Other Liabilities Deferred income taxes 1,456.5 1,339.5 Postretirement and postemployment benefits 280.6 265.2 Deferred investment tax credits 97.4 101.4 Other 345.0 426.0 - ---------------------------------------------------------------------------------------------------------------------- Total deferred credits and other liabilities 2,179.5 2,132.1 - ---------------------------------------------------------------------------------------------------------------------- Long-term Debt Long-term debt of Constellation Energy 1,135.0 1,000.0 Long-term debt of nonregulated businesses 360.2 670.0 First refunding mortgage bonds of BGE 1,174.7 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 (4.7) (5.4) Current portion of long-term debt (1,215.8) (906.6) - ---------------------------------------------------------------------------------------------------------------------- Total long-term debt 2,589.0 3,159.3 - ---------------------------------------------------------------------------------------------------------------------- BGE Preference Stock Not Subject to Mandatory Redemption 190.0 190.0 Common Shareholders' Equity Common stock 2,049.5 1,538.7 Retained earnings 1,749.7 1,592.3 Accumulated other comprehensive income 165.8 22.0 - ---------------------------------------------------------------------------------------------------------------------- Total common shareholders' equity 3,965.0 3,153.0 - ---------------------------------------------------------------------------------------------------------------------- Total capitalization 6,744.0 6,502.3 - ---------------------------------------------------------------------------------------------------------------------- Total Liabilities and Capitalization $13,736.6 $13,121.1 ======================================================================================================================
* 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) Six Months Ended June 30, - ---------------------------------------------------------------------------------------------------------------------- 2001 2000 (In millions) Cash Flows From Operating Activities Net income $ 187.4 $111.7 Adjustments to reconcile to net cash provided by operating activities Cumulative effect of change in accounting principle (8.5) -- Depreciation and amortization 227.6 288.2 Deferred income taxes (1.2) (23.7) Investment tax credit adjustments (4.1) (4.2) Deferred fuel costs 42.8 9.8 Accrued pension and postemployment benefits 14.0 12.1 Gains on sale of investments and subsidiaries (35.7) (14.3) Deregulation transition cost -- 24.0 Equity in earnings of affiliates and joint ventures (net) (14.2) 5.3 Changes in assets from energy trading activities (212.6) (767.2) Changes in liabilities from energy trading activities 104.8 671.0 Changes in other current assets 94.0 59.8 Changes in other current liabilities (99.0) (1.3) Other (34.3) (28.9) - ---------------------------------------------------------------------------------------------------------------------- Net cash provided by operating activities 261.0 342.3 - ---------------------------------------------------------------------------------------------------------------------- Cash Flows From Investing Activities Purchases of property, plant and equipment and other capital expenditures (669.6) (360.7) Sale of (investment in) Orion 26.2 (101.5) Contributions to nuclear decommissioning trust fund (13.2) (8.8) Purchases of marketable equity securities (23.7) (2.4) Sales of marketable equity securities 70.9 14.4 Other investments 40.9 0.9 - ---------------------------------------------------------------------------------------------------------------------- Net cash used in investing activities (568.5) (458.1) - ---------------------------------------------------------------------------------------------------------------------- Cash Flows From Financing Activities Net issuance (maturity) of short-term borrowings 66.6 (156.7) Proceeds from issuance of Long-term debt 844.6 800.1 Common stock 504.4 6.0 Reacquisition of long-term debt (1,106.6) (347.7) Common stock dividends paid (81.4) (125.6) Other 9.0 (6.6) - ---------------------------------------------------------------------------------------------------------------------- Net cash provided by financing activities 236.6 169.5 - ---------------------------------------------------------------------------------------------------------------------- Net (Decrease) Increase in Cash and Cash Equivalents (70.9) 53.7 Cash and Cash Equivalents at Beginning of Period 182.7 92.7 - ---------------------------------------------------------------------------------------------------------------------- Cash and Cash Equivalents at End of Period $ 111.8 $146.4 ====================================================================================================================== Other Cash Flow Information Cash paid during the period for: Interest (net of amounts capitalized) $116.9 $131.5 Income taxes $133.5 $110.9
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 Six Months Ended June 30, June 30, 2001 2000 2001 2000 - ---------------------------------------------------------------------------------------------------------------------- (In millions) Revenues Electric revenues $497.5 $565.4 $ 989.8 $1,090.0 Gas revenues 109.7 92.7 467.3 287.8 - ---------------------------------------------------------------------------------------------------------------------- Total revenues 607.2 658.1 1,457.1 1,377.8 Expenses Operating expenses: Electric fuel and purchased energy 293.9 124.7 559.7 244.1 Gas purchased for resale 52.2 40.9 305.1 143.8 Operations and maintenance 87.2 191.9 173.6 369.5 Depreciation and amortization 55.6 123.2 113.3 248.9 Taxes other than income taxes 43.3 50.4 89.3 110.5 - ---------------------------------------------------------------------------------------------------------------------- Total expenses 532.2 531.1 1,241.0 1,116.8 - ---------------------------------------------------------------------------------------------------------------------- Income from Operations 75.0 127.0 216.1 261.0 Other Income/(Expense) 1.2 1.6 (1.0) 4.4 - ---------------------------------------------------------------------------------------------------------------------- Income Before Fixed Charges and Income Taxes 76.2 128.6 215.1 265.4 Fixed Charges Interest expense (net) 39.2 47.8 81.5 96.1 Allowance for borrowed funds used during construction (1.1) (1.4) (1.4) (2.6) - ---------------------------------------------------------------------------------------------------------------------- Total fixed charges 38.1 46.4 80.1 93.5 - ---------------------------------------------------------------------------------------------------------------------- Income Before Income Taxes 38.1 82.2 135.0 171.9 Income Taxes Current 19.5 44.0 60.3 101.8 Deferred (4.0) (12.2) (5.7) (32.4) Investment tax credit adjustments (0.6) (2.0) (1.2) (4.1) - ---------------------------------------------------------------------------------------------------------------------- Total income taxes 14.9 29.8 53.4 65.3 - ---------------------------------------------------------------------------------------------------------------------- Net Income 23.2 52.4 81.6 106.6 Preference Stock Dividends 3.3 3.3 6.6 6.6 - ---------------------------------------------------------------------------------------------------------------------- Earnings Applicable to Common Stock $ 19.9 $ 49.1 $ 75.0 $ 100.0 ======================================================================================================================
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
June 30, December 31, 2001* 2000 - ---------------------------------------------------------------------------------------------------------------------- (In millions) Assets Current Assets Cash and cash equivalents $ 40.2 $ 21.3 Accounts receivable (net of allowance for uncollectibles of $13.4 and $13.4 respectively) 367.6 413.0 Accounts receivable, affiliated companies 298.7 133.2 Note receivable, affiliated company -- 87.0 Fuel stocks 46.1 34.1 Materials and supplies 37.5 37.3 Prepaid taxes other than income taxes 1.7 44.9 Other 6.7 4.7 - ---------------------------------------------------------------------------------------------------------------------- Total current assets 798.5 775.5 - ---------------------------------------------------------------------------------------------------------------------- Other Assets Net pension asset 106.0 100.2 Other 72.7 68.7 - ---------------------------------------------------------------------------------------------------------------------- Other assets 178.7 168.9 - ---------------------------------------------------------------------------------------------------------------------- Utility Plant Plant in service Electric 3,306.7 3,259.0 Gas 998.7 988.4 Common 477.6 532.9 - ---------------------------------------------------------------------------------------------------------------------- Total plant in service 4,783.0 4,780.3 Accumulated depreciation (1,697.8) (1,700.3) - ---------------------------------------------------------------------------------------------------------------------- Net plant in service 3,085.2 3,080.0 Construction work in progress 86.3 75.3 Plant held for future use 4.5 4.5 - ---------------------------------------------------------------------------------------------------------------------- Net utility plant 3,176.0 3,159.8 - ---------------------------------------------------------------------------------------------------------------------- Deferred Charges Regulatory assets (net) 444.6 514.9 Other 33.4 35.1 - ---------------------------------------------------------------------------------------------------------------------- Total deferred charges 478.0 550.0 - ---------------------------------------------------------------------------------------------------------------------- Total Assets $4,631.2 $4,654.2 ======================================================================================================================
* Unaudited See Notes to Consolidated Financial Statements. 8 BALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARIES PART 1 - FINANCIAL INFORMATION (CONTINUED) Item 1 - Financial Statements Consolidated Balance Sheets
June 30, December 31, 2001* 2000 - ---------------------------------------------------------------------------------------------------------------------- (In millions) Liabilities and Capitalization Current Liabilities Short-term borrowings $ -- $ 32.1 Current portions of long-term debt 551.7 567.6 Accounts payable 84.1 119.3 Accounts payable, affiliated companies 171.6 103.5 Customer deposits 47.1 44.4 Accrued taxes 18.6 25.0 Accrued interest 47.8 43.4 Accrued vacation costs 21.6 20.8 Other 17.5 29.6 - ---------------------------------------------------------------------------------------------------------------------- Total current liabilities 960.0 985.7 - ---------------------------------------------------------------------------------------------------------------------- Deferred Credits and Other Liabilities Deferred income taxes 497.2 508.7 Postretirement and postemployment benefits 241.2 231.2 Deferred investment tax credits 23.8 25.0 Decommissioning of federal uranium enrichment facilities 23.7 23.7 Other 21.7 23.2 - ---------------------------------------------------------------------------------------------------------------------- Total deferred credits and other liabilities 807.6 811.8 - ---------------------------------------------------------------------------------------------------------------------- Long-term Debt First refunding mortgage bonds of BGE 1,174.7 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 41.0 34.0 Unamortized discount and premium (2.5) (3.3) Current portion of long-term debt (551.7) (567.6) - ---------------------------------------------------------------------------------------------------------------------- Total long-term debt 1,801.1 1,864.4 - ---------------------------------------------------------------------------------------------------------------------- Preference Stock Not Subject to Mandatory Redemption 190.0 190.0 Common Shareholder's Equity Common stock 462.4 465.1 Retained earnings 410.1 337.2 - ---------------------------------------------------------------------------------------------------------------------- Total common shareholder's equity 872.5 802.3 - ---------------------------------------------------------------------------------------------------------------------- Total capitalization 2,863.6 2,856.7 - ---------------------------------------------------------------------------------------------------------------------- Total Liabilities and Capitalization $4,631.2 $4,654.2 ======================================================================================================================
* Unaudited See Notes to Consolidated Financial Statements. 9 BALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARIES PART 1 - FINANCIAL INFORMATION (CONTINUED) Item 1 - Financial Statements Consolidated Statements of Cash Flows (Unaudited)
Six Months Ended June 30, 2001 2000 - ---------------------------------------------------------------------------------------------------------------------- (In millions) Cash Flows From Operating Activities Net income $ 81.6 $106.6 Adjustments to reconcile to net cash provided by operating activities Depreciation and amortization 114.4 272.9 Deferred income taxes (5.7) (32.4) Investment tax credit adjustments (1.2) (4.1) Deferred fuel costs 42.8 9.8 Accrued pension and postemployment benefits 5.8 12.0 Allowance for equity funds used during construction (1.4) (1.6) Changes in other current assets (91.7) 42.5 Changes in other current liabilities 24.2 (22.5) Other 13.0 8.8 - ---------------------------------------------------------------------------------------------------------------------- Net cash provided by operating activities 181.8 392.0 - ---------------------------------------------------------------------------------------------------------------------- Cash Flows From Investing Activities Utility construction expenditures (excluding AFC) (121.3) (176.7) Nuclear fuel expenditures -- (39.5) Deferred conservation expenditures (0.3) (0.3) Contributions to nuclear decommissioning trust fund -- (8.8) Other (9.5) (3.9) - ---------------------------------------------------------------------------------------------------------------------- Net cash used in investing activities (131.1) (229.2) - ---------------------------------------------------------------------------------------------------------------------- Cash Flows From Financing Activities Net (maturity)/issuance of short-term borrowings (32.1) 70.3 Proceeds from issuance of long-term debt 206.9 - Reacquisition of long-term debt (200.0) (107.5) Preference stock dividends paid (6.6) (6.6) Distributions to Constellation Energy -- (125.6) Other -- 1.8 - ---------------------------------------------------------------------------------------------------------------------- Net cash used in financing activities (31.8) (167.6) - ---------------------------------------------------------------------------------------------------------------------- Net Increase (Decrease) in Cash and Cash Equivalents 18.9 (4.8) Cash and Cash Equivalents at Beginning of Period 21.3 23.5 - ---------------------------------------------------------------------------------------------------------------------- Cash and Cash Equivalents at End of Period $ 40.2 $ 18.7 ====================================================================================================================== Other Cash Flow Information Cash paid during the period for: Interest (net of amounts capitalized) $78.2 $ 94.2 Income taxes $64.5 $113.1
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 18. Please also refer to the Legal Proceedings section on page 35 for a discussion regarding an appeal of the Restructuring Order. - -------------------------------------------------------------------------------- Information by Operating Segment - -------------------------------- Our reportable operating segments are - Domestic Merchant Energy, Regulated Electric, and Regulated Gas: o Our nonregulated domestic merchant energy business: - provides power marketing, 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, and o Our regulated gas business purchases, transports, and sells natural gas. 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 develop, own, and operate international power projects in Latin America, 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 natural gas through mass marketing efforts, o provide cooling services, o engage in financial investments, and o develop, own and manage real estate and senior-living facilities. 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. 11
Domestic Unallocated Merchant Regulated Regulated Other Corporate Energy Electric Gas Nonregulated Items and Business Business Business Businesses Eliminations Consolidated - --------------------------- -------------- -------------- --------------- ------------- -------------- ------------ For the three months ended June 30, (In millions) 2001 - ---- Unaffiliated revenues $ 90.8 $ 497.4 $109.6 $144.2 $ -- $ 842.0 Intersegment revenues 281.7 0.1 0.1 0.8 (282.7) -- - ---------------------------- ------------- -------------- --------------- ------------- ------------ -------------- Total revenues 372.5 497.5 109.7 145.0 (282.7) 842.0 Net income 52.4 18.0 3.0 2.2 -- 75.6 2000 - ---- Unaffiliated revenues $ 64.1 $ 565.3 $ 91.6 $145.6 $ -- $ 866.6 Intersegment revenues -- 0.1 1.1 -- (1.2) -- - ---------------------------- ------------- -------------- --------------- ------------- ------------ -------------- Total revenues 64.1 565.4 92.7 145.6 (1.2) 866.6 Net income (a) 1.9 47.3 2.3 (11.9) -- 39.6 For the six months ended June 30, 2001 - ---- Unaffiliated revenues $176.7 $ 989.6 $461.8 $359.8 $ -- $1,987.9 Intersegment revenues 532.5 0.2 5.5 1.9 (540.1) -- - ---------------------------- ------------- -------------- --------------- ------------- ------------ -------------- Total revenues 709.2 989.8 467.3 361.7 (540.1) 1,987.9 Cumulative effect of change in accounting principle -- -- -- 8.5 -- 8.5 Net income 94.8 45.7 31.7 15.2 -- 187.4 2000 - ---- Unaffiliated revenues $133.4 $1,089.7 $286.1 $351.4 $ -- $1,860.6 Intersegment revenues -- 0.3 1.7 6.7 (8.7) -- - ---------------------------- ------------- -------------- --------------- ------------- ------------ -------------- Total revenues 133.4 1,090.0 287.8 358.1 (8.7) 1,860.6 Net income (a) 20.1 78.1 22.6 (9.1) -- 111.7 At June 30, 2001 - ---------------- Segment assets $8,068.8 $3,472.3 $1,104.3 $1,475.8 $(384.6) $13,736.6 At December 31, 2000 - -------------------- Segment assets $7,297.8 $3,392.3 $1,089.9 $1,491.5 $(150.4) $13,121.1
(a) Our regulated electric business recorded an expense of $1.7 million for the quarter ended and $4.2 million for the six months ended 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. 12 Financing Activity - ------------------ Constellation Energy - -------------------- As discussed on page 11, effective April 30, 1999, BGE's outstanding common stock automatically became shares of common stock of 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
In connection with the initiative to separate our domestic merchant energy business from our retail services business, Constellation Energy expects to redeem all of its outstanding long-term debt at or prior to the separation (approximately $1.1 billion currently) and to repay any outstanding commercial paper borrowings at that time. The redemption will occur through a combination of open market purchases, tender offers, and redemption calls. In June 2001, Constellation Energy arranged a $2.5 billion revolving credit facility. This facility will be used primarily to fund capital expenditures, and working capital requirements, including commercial paper support, for the domestic merchant energy business, to redeem the $1.1 billion of its outstanding long-term debt, and to repay commercial paper borrowings. Prior to or upon separation, the new merchant energy company will assume this facility and expects to refinance the facility shortly thereafter. In June 2001, Constellation Energy also arranged a $380 million revolving credit facility to be used primarily to support letters of credit and for other short-term financing needs. Prior to or upon separation, the new merchant energy company also will assume this facility. We discuss the separation of our businesses in the Strategy section of Management's Discussion and Analysis on page 19. Constellation Energy also has an existing $188.5 million revolving credit facility available for short-term and long-term needs, including letters of credit. Upon separation, this facility will either be terminated or assumed by the new merchant energy company. As of the date of this report, letters of credit that totaled $178.4 million were issued under all of our facilities. Constellation Energy has issued guarantees in an amount up to $1.3 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 $167.1 million at June 30, 2001. In connection with the separation, the domestic merchant energy guarantees will be replaced by guarantees, letters of credit, or other types of collateral of the new merchant energy company. 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 $276.3 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 20. 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 33 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 they have an interest. At June 30, 2001, the total amount of investment requirements committed to by our domestic merchant energy business was $162.6 million. Environmental Matters - --------------------- Clean Air The Clean Air Act includes two titles designed to reduce emissions of sulfur dioxide and nitrogen oxide (NOx) from electric generating plants - Title IV and Title I. 13 Title IV addresses emissions of sulfur dioxides. For our older plants, we meet the requirements of Title IV through a combination of switching fuels and allowance trading. For newer plants, we meet the requirements of Title IV primarily through facility design, and operational and pollution controls. Title I addresses emissions of NOx. The Environmental Protection Agency (EPA) issued a final rule in 1998 that required up to 85% NOx emissions reduction by 22 states (including Maryland and Pennsylvania). Maryland and Pennsylvania have issued regulations pursuant to EPA's rule. At our Brandon Shores and Wagner facilities in Maryland, we are installing emission reduction equipment that will be in operation by May 2002 in order to meet Maryland's deadline. Emissions reduction equipment will be installed by 2003 at the Keystone plant in Pennsylvania to meet the Pennsylvania deadline. We currently estimate that the controls needed at our generating plants to meet the NOx emission reduction requirements will cost approximately $260 million. Through June 30, 2001, we have spent approximately $167 million to meet these reduction requirements. Future expenditures for NOx reduction will be paid by our domestic merchant energy business. In July 1997, the EPA published new National Ambient Air Quality Standards for very fine particulates and revised standards for ozone attainment. In 1999, these new standards were successfully challenged in court. The EPA appealed the 1999 court rulings to the Supreme Court. In February 2001, the Supreme Court upheld EPA's authority to issue the standards. However, the Supreme Court sent the case back to the lower court and EPA for further proceedings on implementation issues related to the revised ozone standard. The lower court will also address remaining challenges to the fine particulate standard. 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. In December 2000, the EPA issued a determination that coal-fired power plant mercury emissions will be controlled. Final regulations are expected to be issued in 2004 with controls required by 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. We received letters from the EPA requesting us to provide certain information under Section 114 of the Clean Air Act regarding some of our electric generating plants in Maryland and Pennsylvania. This information is to determine compliance with the Clean Air Act and state implementation plan requirements, including potential application of federal new source performance standards. In general, such standards can require the installation of additional air pollution control equipment upon the major modification of an existing plant. We have provided the EPA the requested information. We believe our generating plants have been operated in accordance with the Clean Air Act and the rules implementing this act. However, we cannot estimate the impact of this inquiry on our generating plants, and our financial results, at this time, but the impact could be material if the EPA was successful in any action they might pursue against our facilities. Waste Disposal - -------------- The EPA and several state agencies have notified us that we are considered a potentially responsible party with respect to the cleanup of certain environmentally contaminated sites owned and operated by others. We cannot estimate the cleanup costs for all of these sites. We can, however, estimate that our current 15.47% share of the reasonably possible cleanup costs at one of these sites, Metal Bank of America, a metal reclaimer in Philadelphia, could be as much as $2.3 million higher than amounts we have recorded as a liability on our Consolidated Balance Sheets. This estimate is based on a Record of Decision issued by the EPA. Also, we are coordinating investigation of several sites where gas was manufactured in the past. The investigation of these sites includes reviewing possible actions to remove coal tar. In late December 1996, we signed a consent order with the Maryland Department of the Environment (MDE) that requires us to implement remedial action plans for contamination at and around the Spring Gardens site, located in Baltimore, Maryland. We submitted the required remedial action plans and they were approved by the MDE. Based on the remedial action plans, the costs we consider to be probable to remedy the contamination are estimated to total $47 million. We have recorded these costs as a liability on our Consolidated Balance Sheets and have deferred these costs, net of accumulated amortization and amounts we recovered from insurance companies, as a regulatory asset. Because of the results of studies at these sites, it is reasonably possible that these additional costs could exceed the amount we recognized by approximately $14 million. We discuss this further in Note 5 of our 2000 Annual Report on Form 10-K. Through June 30, 2001, we have spent approximately $36 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. 14 Nuclear Insurance - ----------------- If there was an accident or an extended outage at either unit of the Calvert Cliffs Nuclear Power Plant (Calvert Cliffs), it could have a substantial adverse financial effect on us. The primary contingencies that would result from an incident at Calvert Cliffs could include: o physical damage to the plant, 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. Furthermore, the costs that could result from a covered major accident or a covered extended outage at either of the Calvert Cliffs units could exceed our insurance coverage limits. Insurance for Calvert Cliffs and Third Party Claims - --------------------------------------------------- For physical damage to Calvert Cliffs, we have $2.75 billion of property insurance from an industry mutual insurance company. If an outage at either of the two units at Calvert Cliffs 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, provided by an industry mutual insurance company. This amount can be reduced by up to $98.0 million per unit if an outage at both units of the 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 $16 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 $176.2 million per incident. That amount would be payable at a rate of $20 million per year. Insurance for Worker Radiation Claims - ------------------------------------- As an operator of a commercial nuclear power plant 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. 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 are collecting this accumulated difference from customers over the twelve-month period beginning October 2000. California Power Purchase Agreements - ------------------------------------ Our domestic generation operation has $304.0 million invested in 14 projects that sell electricity in California under power purchase agreements called "Interim Standard Offer No. 4" agreements. 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. In 2001, the prices received under these agreements were higher than prior periods due to increases in the variable-rate pricing terms. However, due to the uncertainties in California, the increases in prices may not be indicative of future prices. We discuss the developments in California in the Current Issues--Electric Competition section on page 21. We also describe these projects and the transition process in Note 3 and Note 10 of our 2000 Annual Report on Form 10-K. 15 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. The cost of BGE's purchased energy from nonregulated affiliates of Constellation Energy to meet its standard offer service obligation was $281.2 million for the quarter and $532.5 million for the six months ended June 30, 2001. 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 $6.1 million for the quarter ended June 30, 2001 compared to $6.1 million for the same period in 2000 and $10.2 million for the six months ended June 30, 2001 compared to $7.3 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 intercompany 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 below. Under SFAS No. 133, changes in the value of derivatives designated as hedges that are effective in offsetting the variability in cash flows of forecasted transactions are recognized in other comprehensive income until the forecasted transactions occur. The ineffective portion of changes in fair value of derivatives used as cash-flow hedges is immediately recognized in earnings. In accordance with the transition provisions of SFAS No. 133, we recorded the following at January 1, 2001: o an $8.5 million after-tax cumulative effect adjustment that increased earnings, and o a $35.5 million after-tax cumulative effect adjustment that reduced other comprehensive income. The cumulative effect adjustment recorded in earnings represents the fair value as of January 1, 2001 of a warrant for 705,900 shares of common stock of Orion 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. We can exercise the warrant for an equivalent number of shares of Orion's common stock with the payment of the full exercise price. We also can exercise the warrant without payment and be entitled to a number of shares of Orion's common stock equivalent to the difference between the aggregate current market price less the aggregate exercise price, divided by the current market price of one share of common stock. 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 for Derivatives 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. 16 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, and Constellation Power. Presently, the majority of the generating capacity controlled by our domestic merchant energy business is used to provide standard offer service to BGE. However, beginning in July 2002, we expect approximately 1,000 megawatts of industrial customer load will leave BGE's standard offer service. The remainder of our domestic merchant energy business' standard offer service arrangement with BGE terminates on June 30, 2003. However, BGE has solicited bids for the supply of its standard offer service from July 1, 2003 through June 30, 2006. Constellation Power Source submitted a bid. 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 June 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 2003 through 2010. At June 30, 2001, we recorded mark-to-market gains of $50.8 million on derivatives designated as cash-flow hedges in "Accumulated Other Comprehensive Income" and in "Other Assets" in our Consolidated Balance Sheets. We do not expect to reclassify any of this amount into earnings during the next twelve months. For the quarter and six months ended June 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. Accounting Standards Issued - --------------------------- 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. 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 June 30, 2001, the unrealized gain on our investment in Orion was $124.6 million. 17 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 11. 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 20. As a result of these changes, our domestic merchant energy business includes the: o wholesale power marketing 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 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 with a service territory in the City of Baltimore and all or part of ten counties in Central Maryland. Our other nonregulated businesses include the: o Latin American power projects and investments of Constellation Power and subsidiaries, 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, and o real estate and senior-living facilities of Constellation Real Estate Group, Inc. As discussed further in the Strategy section on page 19, on October 23, 2000, we announced initiatives to separate our domestic merchant energy business from our remaining businesses. These remaining businesses include BGE and the other nonregulated businesses described above. 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 six months ended June 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. In addition, we announced our intention to separate our domestic merchant energy business from our remaining businesses. Accordingly, the results of operations and financial condition described in this discussion and analysis are not necessarily indicative of future performance. 18 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 regulatory change. Prior to July 1, 2000, the majority of our earnings were from BGE. Going forward, prior to separating into two companies, we expect to derive almost two-thirds of our earnings from our domestic merchant energy business. While BGE continues to be regulated and to deliver electricity and natural gas through its core distribution business, our primary growth strategies center on the nonregulated domestic merchant energy business. On October 23, 2000, we announced three initiatives to advance our growth strategies. The first initiative is that we entered into an agreement (the "Agreement") with an affiliate of The Goldman Sachs Group, Inc. ("Goldman Sachs"). Under the terms of the Agreement, Goldman Sachs will acquire up to a 17.5% equity interest in our domestic merchant energy business, which will be consolidated under a single holding company ("new Constellation Energy"). Goldman Sachs will also acquire a ten-year warrant for up to 13% of new Constellation Energy's common stock (subject to certain adjustments). The warrant is exercisable six months after new Constellation Energy's common stock becomes publicly available. The amount of common stock which Goldman Sachs may receive upon exercise will be equal to the excess of the market price of new Constellation Energy's common stock at the time of exercise over the exercise price of $60 per share for all the stock subject to the warrant, divided by the market price. New Constellation Energy may at its option pay Goldman Sachs such excess in cash. Goldman Sachs is acquiring its interest and the warrant in exchange for $250 million in cash (subject to adjustment in certain instances) and certain assets related to our power marketing operation. At closing, Goldman Sachs' existing services agreement with our power marketing operation will terminate. The second initiative is a plan to separate our domestic merchant energy business from our remaining businesses as discussed in the introduction. The separation will create two stand-alone, publicly traded energy companies. One will be a merchant energy business engaged in wholesale power marketing and generation under the name "Constellation Energy Group" after the separation. The other will be a regional retail energy delivery and energy services company, BGE Corp., which will include BGE, our other nonregulated businesses, and our investment in Orion Power Holdings, Inc. ("Orion"). As a result of the separation, shareholders will continue to own all of Constellation Energy's current businesses through their ownership of the stock of the new Constellation Energy Group and of BGE Corp. The third initiative is a change in our common stock dividend policy effective April 2001. In a move closely aligned with our separation plan, effective April 2001, our annual dividend was set at $.48 per share. After the separation, BGE Corp. expects to pay initial annual dividends of $.48 per share. Constellation Energy Group, as a growing merchant energy company, initially expects to reinvest its earnings in order to fund its growth plans and not to pay a dividend. The closing of the transaction with Goldman Sachs and the separation are subject to customary closing conditions and contingent upon obtaining regulatory approvals and a Private Letter Ruling from the Internal Revenue Service regarding certain tax matters. We expect to complete the transaction and separation by late 2001. At the date of this report, we have received approval from the Federal Energy Regulatory Commission (FERC) and the Nuclear Regulatory Commission (NRC). Upon separation, the strategy for the new Constellation Energy is to be a leading competitive provider of energy solutions for wholesale customers in North America. To achieve this, new Constellation Energy expects to continue to expand its marketing and risk management operations supported by geographic, fuel, and dispatch diversification. In addition, new Constellation Energy expects to continue to grow its generation business through acquisition, development, and contractual arrangements. The primary strategy for BGE Corp. is to expand its core utility and non-regulated retail energy services businesses throughout surrounding areas. Currently, our domestic merchant energy business controls over 10,000 megawatts of generation including 1,100 megawatts of natural gas-fired peaking capacity that commenced operations in the Mid-Atlantic and Mid-West regions during mid-summer 2001. In December 2000, we announced that a subsidiary of Constellation Nuclear will purchase 1,550 megawatts of the 1,757 megawatts total generating capacity of the Nine Mile Point nuclear power plant located in Scriba, New York. The closing of the Nine Mile Point power plant was expected to take place by July 1, 2001. The total purchase price based on the expected closing date, including fuel, was $815 million. However, the closing date has been delayed as the sellers and New York State regulators work to settle all remaining stranded cost issues. The contract provides for a reduction in the purchase price for each day that the closing is delayed beyond the target date of July 1, 2001. At the date of this report, we have received approval from the FERC and the NRC. We expect to close on the Nine Mile purchase later this year. We discuss the planned acquisition of the 19 Nine Mile Point power plant in more detail in Note 10 of our 2000 Annual Report on Form 10-K. We also have an additional 6,000 megawatts of natural gas-fired peaking and combined cycle production facilities in various regions of North America under construction or in development. We are currently in the process of soliciting offers to purchase our Latin American operations due to our concentration on domestic merchant energy. We plan to sell the businesses if offers received are reasonable relative to the cash flows expected to be earned if we continue to own the businesses. We also might consider one or more of the following strategies: o the complete or partial separation of our transmission and distribution functions, o mergers or acquisitions of utility or non-utility businesses, and sale of o 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 37. 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. 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. 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. 20 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. The energy and capacity for the remaining years in the transition period were competitively bid and BGE has received several bids including one for Constellation Power Source. BGE currently is evaluating these bids and expects to award contracts by the end of August 2001. We expect the Maryland PSC to review the results of the competitive bid process. 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 is focused on expanding its business through marketing energy products, including structured transactions, to wholesale customers and acquiring control of 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 may affect our domestic merchant energy business strategy. Our domestic merchant energy business has $304.0 million invested in power projects that sell 142 megawatts of electricity in California under power purchase agreements as discussed in the California Power Purchase Agreements section in the Notes to Consolidated Financial Statements on page 15. The counterparties to the agreements are two California investor-owned utilities, Southern California Edison Company (SCE) and Pacific Gas and Electric Company (PGE). Due to various factors, including shortage of generation and the high cost of natural gas, these utilities' financial condition has been severely impacted because they are paying more for power than they are allowed to recover from their customers under the deregulation plan in California. As a result, these utilities did not maintain current payments for the power they purchased to meet their customers' energy needs and the credit ratings of these utilities were downgraded below investment grade. Unable to meet its obligation to power suppliers, the California Power Exchange ceased operations in January 2001 and filed for bankruptcy in March 2001. California's Department of Water Resources has since assumed the role of electricity procurement in California and is considering raising money through the sale of bonds to pay back creditors of the California Power Exchange and the California Independent System Operator. Further, on April 6, 2001, PGE filed for protection under Chapter 11 of the United States Bankruptcy Code. Due to the deteriorating financial condition of these utilities, our California projects did not receive full payment for electricity delivered to these utilities for the period November 1, 2000 through April 6, 2001. Our projects that sell power to SCE began receiving current payments for power delivered beginning April 1, 2001, and our projects that sell power to PGE began receiving current payments for power delivered beginning April 7, 2001. Our portion of the amount due from these utilities for the period November 1, 2000 through April 6, 2001 was approximately $50 million. While we expect to be paid the amount owed to us, we cannot predict when payment will occur or if full payment will be received. We have taken reserves in amounts we believe to be reasonable under the current circumstances. However, if the ultimate resolution of the events in California prevents collection of unpaid balances under power purchase agreements by some or all of our projects, in an amount in excess of the reserves that we have taken, it could have a material impact on our financial results. Additionally, if the events in California result in a modification or termination of these agreements that reduces future cash flows, we would have to evaluate whether our investments in the power projects that are parties to the agreements are impaired. An impairment of these investments could have a material impact on our financial results. Our domestic merchant energy business does not have any other direct agreements with these utilities. However, we may be impacted if one or more of our other counterparties are significantly affected by the events in California, or by the operation of the California Department of Water Resources and the California Independent System Operator. 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. 21 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 are collecting this accumulated difference from customers over the twelve-month period beginning October 2000. Effective July 1, 2000, earnings are affected by the changes in the cost of fuel and energy. 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 29 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 proceeding is currently ongoing. 22 As a member of PJM, an existing ISO, BGE does not expect to be materially impacted by Order 2000 or the July 12, 2001 order. However, we are appealing 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 agreed to hear an appeal by others of FERC Order 888. 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. Current 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 29. 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 heating degree days in the quarters and six months ended June 30, 2001 and 2000, and the percentage change in the number of degree days between these periods in the following table:
Quarter Six Months Ended Ended June 30 June 30 2001 2000 2001 2000 - -------------------------------------------------- Heating degree days 471 512 2,918 2,817 Percent change from prior period (8.0)% 3.6% Cooling degree days 262 263 262 268 Percent change from prior period (0.4)% (2.2)%
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. 23 Results of Operations for the Quarter and Six Months Ended June 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, income taxes, and other income are discussed in the aggregate for all segments in the Consolidated Nonoperating Income and Expenses section on page 31. Overview - --------
Total Earnings Per Share of Common Stock Quarter Ended Six Months Ended June 30, June 30, 2001* 2000 2001* 2000 - ----------------------------------------------------------- Earnings before nonrecurring charges included in operations: Domestic merchant energy $.32 $.11 $ .60 $.24 Regulated electric .11 .32 .29 .55 Regulated gas .02 .02 .20 .15 Other nonregulated .01 (.08) .04 (.06) - ----------------------------------------------------------- Total earnings per share before nonrecurring charges included in operations: .46 .37 1.13 .88 Nonrecurring charges included in operations: Deregulation transition cost -- (.10) -- (.10) TVSERP -- (.01) -- (.03) - ----------------------------------------------------------- Earnings per share before cumulative effect of change in accounting principle .46 .26 1.13 .75 Cumulative effect of change in accounting principle, net of income taxes -- -- .06 -- - ----------------------------------------------------------- Total earnings per share $.46 $.26 $1.19 $.75 ===========================================================
*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 20. Quarter Ended June 30, 2001 - --------------------------- Our total earnings for the quarter ended June 30, 2001 increased $36.0 million, or $.20 per share, compared to the same period of 2000. Our total earnings increased mostly because of the following: o We recorded $37.5 million pre-tax, or approximately $.15 per share, of amortization expense for the reduction of our generating plants associated with the Restructuring Order in the second quarter of 2000 that had a negative impact in that quarter. o We recorded a nonrecurring expense of $15.0 million, after-tax, for deregulation transition cost to a third party incurred by our power marketing business to provide BGE's standard offer service requirements in the second quarter of 2000 that had a negative impact in that quarter. o We recorded a nonrecurring expense of $1.7 million, after-tax, for BGE employees that elected to participate in a Targeted Voluntary Special Early Retirement Program (TVSERP) in the second quarter of 2000 that had a negative impact in that quarter. These were partially offset by $11.6 million pre-tax, or $.04 per share, recorded in the second quarter 2001 related to the impact of a 6.5% annual residential rate reduction that was effective July 1, 2000. Six Months Ended June 30, 2001 - ------------------------------ Our total earnings for the six months ended June 30, 2001 increased $75.7 million, or $.44 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 a third party incurred by our power marketing business that had a negative impact in 2000 as discussed above. o We recorded a nonrecurring expense of $4.2 million, after-tax, for BGE employees that elected to participate in the 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. These 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. 24 Domestic Merchant Energy Business - --------------------------------- Our domestic merchant energy business engages primarily in power marketing and domestic power generation. 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 20, 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. 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. 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. 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. We cannot estimate the impact of the increased financial risks associated with the competitive wholesale electricity market. However, these financial risks could have a material impact on our financial results.
Earnings - -------- Quarter Ended Six Months Ended June 30, June 30, 2001 2000 2001 2000 - ----------------------------------------------------------- (In millions, except per share amounts) Revenues $372.5 $64.1 $709.2 $133.4 Operating expenses 243.6 54.3 461.8 90.6 Depreciation and amortization 39.9 1.8 79.5 3.3 Taxes other than income taxes 11.2 -- 22.4 -- - ----------------------------------------------------------- Income from operations $ 77.8 $ 8.0 $145.5 $ 39.5 =========================================================== Net income $ 52.4 $ 1.9 $ 94.8 $ 20.1 =========================================================== Total earnings per share before nonrecurring charges included in operations: $.32 $.11 $.60 $.24 Deregulation transition cost -- (.10) -- (.10) - ----------------------------------------------------------- Earnings per share $.32 $.01 $.60 $.14 ===========================================================
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 12 provides a reconciliation of operating results by segment to our Consolidated Financial Statements. Revenues - -------- During the quarter ended June 30, 2001, domestic merchant energy revenues increased $308.4 million compared to the same period of 2000 mostly because of: o a $281.2 million increase related to providing BGE the energy and capacity required to meet its standard offer service obligation effective July 1, 2000, and o a $43.4 million increase related to CTC and decommissioning revenues included in the domestic merchant energy business effective July 1, 2000. These increases were partially offset by lower revenues from our domestic generation operation. During the six months ended June 30, 2001, domestic merchant energy revenues increased $575.8 million compared to the same period of 2000 mostly because of: o a $532.5 million increase related to providing BGE the energy and capacity required to meet its standard offer service obligation effective July 1, 2000, o a $94.1 million increase related to CTC and decommissioning revenues included in the domestic merchant energy business effective July 1, 2000. These increases were partially offset by lower 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. 25 Power Marketing - --------------- During the quarter ended June 30, 2001, power marketing revenues increased slightly compared to the same period of 2000 mostly because of higher revenues from new structured transactions partially offset by the effect of unfavorable market price changes on open trading positions. During the six months ended June 30, 2001, power marketing revenues decreased compared to the same period of 2000 mostly because of the effect of unfavorable market price changes on open trading positions partially offset by higher revenues from new 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. Domestic Generation - ------------------- During the quarter ended June 30, 2001, domestic generation revenues decreased compared to the same period of 2000 mostly because in April 2000, Constellation Operating Services Inc. (COSI), a subsidiary of Constellation Power, Inc., recognized a $13.3 million gain on the termination of an operating arrangement and sale of certain subsidiaries to Orion Power Holdings Inc. During the six months ended June 30, 2001, domestic generation revenues decreased compared to the same period of 2000 mostly because of the 2000 gain discussed above partially offset by a $9.5 million gain on the sale of a project under development located in the PJM region recorded in March 2001. California Power Purchase Agreements - ------------------------------------ Our domestic generation operation has $304.0 million invested in 14 projects that sell electricity in California to SCE and PGE under power purchase agreements called "Interim Standard Offer No. 4" 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 six months ended June 30, 2001, revenues from these projects were about the same compared to the same periods of 2000. While energy rates were higher for the six months period compared to the same period of 2000, this was offset by reserves established for our exposure in California. We discuss the developments in California in the Current Issues--Electric Competition section on page 21. 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 $189.3 million for the quarter and $371.2 million for the six months ended June 30, 2001 compared to the same periods of 2000 mostly because of: o increases in fuel costs of $103.0 million for the quarter and $206.4 million for the six months period, and o increases in operations and maintenance costs of $102.7 million for the quarter and $194.7 million for the six months period. These costs were associated with the generation plants that were transferred from BGE effective July 1, 2000. This was partially offset by lower operating expenses by our power marketing operation mostly because in the second quarter of 2000, this operation recognized $24.0 million for deregulation transition cost to a third party that had a negative impact in that period. The power marketing operation also had lower transaction related expenses. Depreciation and Amortization Expense - ------------------------------------- Domestic merchant energy depreciation and amortization expense increased $38.1 million for the quarter and $76.2 million for the six months ended June 30, 2001 compared to the same periods of 2000 mostly because of expenses associated with the generation plants that were transferred from BGE effective July 1, 2000. Taxes Other than Income Taxes - ----------------------------- Domestic merchant energy taxes other than income taxes increased $11.2 million for the quarter and $22.4 million for the six months ended June 30, 2001 compared to the same periods of 2000 mostly because of taxes other than income taxes associated with the generation plants that were transferred from BGE effective July 1, 2000. 26 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 Six Months Ended June 30, June 30, 2001 2000 2001 2000 - -------------------------------------------------------- (In millions, except per share amounts) Electric revenues $497.5 $565.4 $989.8 $1,090.0 Electric fuel and purchased energy 293.9 124.7 559.7 244.1 Operations and maintenance 62.9 168.6 124.7 322.7 Depreciation and amortization 43.3 112.2 86.7 224.8 Taxes other than income taxes 35.0 44.3 70.9 90.4 - -------------------------------------------------------- Income from operations $ 62.4 $115.6 $147.8 $ 208.0 ======================================================== Net income $ 18.0 $ 47.3 45.7 $ 78.1 ======================================================== Total earnings per share before nonrecurring charges included in operations: $.11 $.32 $.29 $.55 TVSERP -- (.01) -- (.03) - -------------------------------------------------------- Earnings per share $.11 $.31 $.29 $.52 ========================================================
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 12 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 Six Months Ended Ended June 30, June 30, 2001 vs. 2000 2001 vs. 2000 - --------------------------------------------------- (In millions) Electric system sales volumes $(0.1) $ 8.9 Rates (48.4) (84.3) Fuel rate surcharge 12.5 27.3 - --------------------------------------------------- Total change in electric revenues from electric system sales (36.0) (48.1) Interchange and other sales (30.9) (53.8) Other (1.0) 1.7 - --------------------------------------------------- Total change in electric revenues $(67.9) $(100.2) ===================================================
Electric System Sales Volumes - ----------------------------- "Electric system sales volumes" are sales to customers in our service territory at rates set by the Maryland PSC. 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 Ended Six Months Ended June 30, June 30, 2001 vs. 2000 2001 vs. 2000 - ----------------------------------------------------- Residential (0.6)% 3.2% Commercial 0.2 1.5 Industrial 1.0 0.3
During the quarter ended June 30, 2001, we sold about the same amount of electricity to all customers compared to the same period of 2000. During the six months ended June 30, 2001, we sold more electricity to residential customers compared to the same period of 2000 due to higher usage per customer and an increased number of customers. We sold more electricity to commercial customers mostly due to an increased number of customers. We sold about the same amount of electricity to 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 decreased compared to the same periods of 2000 mostly due to the decreases caused by: o the 6.5% annual residential rate reduction of $11.6 million for the quarter and $17.6 million for the six months period, and o the $43.4 million for the quarter and $94.1 million for the six months period related to the 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. 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 on page 28. 27 Interchange and Other Sales - --------------------------- "Interchange and other sales" are sales in the PJM energy market and to others. PJM is an 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 quarter and six months ended June 30, 2001 compared to the same periods of 2000. Electric Fuel and Purchased Energy Expenses - -------------------------------------------
Quarter Ended Six Months Ended June 30, June 30, 2001 2000 2001 2000 - --------------------------------------------------------- (In millions) Actual costs $281.6 $131.2 $532.9 $253.8 Net recovery (deferral) of costs under electric fuel rate clause 12.3 (6.5) 26.8 (9.7) - --------------------------------------------------------- Total electric fuel and purchased energy expenses $293.9 $124.7 $559.7 $244.1 =========================================================
Actual Costs - ------------ Our actual costs of fuel and purchased energy were higher compared to the same period of 2000 mostly because of the deregulation of electric generation. As discussed in the Current Issues--Electric Competition section on page 20, 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. The cost of energy BGE purchased from our domestic merchant energy business was $281.2 million for the quarter and $532.5 million for the six months ended June 30, 2001. The higher amount paid for purchased energy is offset by the absence of $103.0 million for the quarter and $206.4 million for the six months 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 are collecting this accumulated difference from customers over the twelve-month period beginning October 2000. Electric Operations and Maintenance Expenses - -------------------------------------------- Regulated electric operations and maintenance expenses decreased $105.7 million for the quarter and $198.0 million for the six months ended June 30, 2001 compared to the same periods of 2000 mostly because of the following: o Effective July 1, 2000, costs of $102.7 million for the quarter and $194.7 million for the six months period 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 In addition, BGE recognized expenses of $2.8 million for the quarter and $7.0 million for the six months periods for employees that elected to participate in a Targeted Voluntary Special Early Retirement Program in 2000 that had a negative impact in those periods. Electric Depreciation and Amortization Expense - ---------------------------------------------- Regulated electric depreciation and amortization expense decreased $68.9 million for the quarter and $138.1 million for the six months ended June 30, 2001 compared to the same periods of 2000 mostly because of: o the absence of $37.5 million for the quarter and $75.0 million for the six months period of amortization expense recorded in 2000 associated with the $150 million reduction of our generating plants provided for in the Restructuring Order, and o $37.6 million for the quarter and 75.1 million for the six months period 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) and higher amortization associated with regulatory assets. Electric Taxes Other Than Income Taxes - -------------------------------------- Regulated electric taxes other than income taxes decreased $9.3 million for the quarter and $19.5 million for the six months ended compared to the same periods 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. 28 Regulated Gas Business - ---------------------- Earnings - --------
Quarter Ended Six Months Ended June 30, June 30, 2001 2000 2001 2000 - -------------------------------------------------------- (In millions, except per share amounts) Gas revenues $109.7 $92.7 $467.3 $287.8 Gas purchased for resale 52.2 40.9 305.1 143.8 Operations and maintenance 24.6 23.3 49.2 46.9 Depreciation and amortization 12.2 11.1 26.5 24.2 Taxes other than income taxes 8.3 6.1 18.4 20.0 - -------------------------------------------------------- Income from operations $ 12.4 $11.3 $ 68.1 $ 52.9 ======================================================== Net income $ 3.0 $ 2.3 $ 31.7 $ 22.6 ======================================================== Earnings per share $.02 $.02 $.20 $.15 ========================================================
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 12 provides a reconciliation of operating results by segment to our Consolidated Financial Statements. Earnings from the regulated gas business increased during the six months ended June 30, 2001 compared to 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 Ended Six Months Ended June 30, June 30, 2001 vs. 2000 2001 vs. 2000 - -------------------------------------------------------- (In millions) Gas system sales volumes $ 0.2 $ 16.7 Base rates 1.8 3.3 Weather normalization 1.5 (5.9) Gas cost adjustments 11.2 116.2 - -------------------------------------------------------- Total change in gas revenues from gas system sales 14.7 130.3 Off-system sales 1.4 47.6 Other 0.9 1.6 - -------------------------------------------------------- Total change in gas revenues $17.0 $179.5 ========================================================
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 Six Months Ended June 30, June 30, 2001 vs. 2000 2001 vs. 2000 - ---------------------------------------------------- Residential (3.0)% 8.3% Commercial 10.0 3.9 Industrial (30.1) (27.3)
During the quarter ended June 30, 2001, we sold less gas to residential customers compared to the same period of 2000 mostly due to milder weather 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 switching to lower cost alternative fuel sources. During the six months ended June 30, 2001, we sold more gas to residential customers compared to the same periods 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 colder winter weather and 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 switching to lower cost alternative fuel sources. Base Rates - ---------- During the quarter and six months ended June 30, 2001, base rate revenues increased compared to the same periods 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 June 30, 2001, the shareholders' portion was about the same compared to the same period of 2000. 29 During the six months ended June 30, 2001, the shareholders' portion increased $3.4 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 and six months ended June 30, 2001, gas cost adjustment revenues increased compared to the same periods of 2000 mostly because we sold more gas at a higher price to non-delivery service customers. In 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 June 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. During the six months ended June 30, 2001, revenues from off-system gas sales increased compared to the same period of 2000 mostly because we sold more gas off-system at a higher price. In 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 June 30, 2001, our gas costs increased compared to the same period of 2000 mostly because we bought gas at a higher price. During the six months ended June 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 six months ended June 30, 2001, other gas operating expenses were about the same compared to the same periods of 2000. Other Nonregulated Businesses - ----------------------------- Earnings - --------
Quarter Ended Six Months Ended June 30, June 30, 2001 2000 2001 2000 - ------------------------------------------------------------ (In millions, except per share amounts) Revenues $145.0 $145.6 $361.7 $358.1 Operating expenses 120.6 141.5 305.1 328.3 Depreciation and amortization 6.6 5.5 12.9 10.8 Taxes other than income taxes 1.0 0.7 2.2 1.9 - ------------------------------------------------------------ Income from operations $ 16.8 $ (2.1) $ 41.5 $ 17.1 ============================================================ Net income before cumulative effect of change in accounting principle $ 2.2 $(11.9) $ 6.7 $ (9.1) Cumulative effect of change in accounting principle -- -- 8.5 -- - ------------------------------------------------------------ Net income $ 2.2 $(11.9) $ 15.2 $ (9.1) ============================================================ Earnings per share before cumulative effect of change in accounting principle $.01 $(.08) $.04 $(.06) Cumulative effect of change in accounting principle -- -- .06 -- - ------------------------------------------------------------ Earnings per share $.01 $(.08) $.10 $(.06) ============================================================
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 12 provides a reconciliation of operating results by segment to our Consolidated Financial Statements. During the quarter ended June 30, 2001, earnings from our other nonregulated businesses increased compared to the same period of 2000 mostly because of a $9.0 million after-tax gain on the sale of one million shares of the Orion investment and better market performance in our financial investments business compared to the prior period, partially offset by a decline in the fair value of the Orion warrant. Under SFAS No. 133, we are required to mark-to-market the value of the Orion warrant through earnings each reporting period. The value of the warrant may fluctuate under mark-to-market accounting based on changes in the stock price of Orion and the volatility of that price in future periods. We discuss the Orion warrant further in the Accounting Standard Adopted section of the Notes to Consolidated Financial Statements on page 16. During the six months ended June 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 as discussed above. 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. o Better market performance in our financial investments business. 30 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 and six months ended June 30, 2001, total fixed charges decreased compared to the same periods of 2000 mostly because of lower interest rates, offset partially by a higher level of debt outstanding. Income Taxes - ------------ During the quarter and six months ended June 30, 2001, our total income taxes increased compared to the same periods of 2000 mostly because we had higher taxable income from our domestic merchant energy and other nonregulated businesses partially offset by lower taxable income from the utility business. - -------------------------------------------------------------------------------- Financial Condition - ------------------- Cash Flows - ----------
Six Months Ended June 30, 2001 2000 - ----------------------------------------------------- (In millions) Cash provided by (used in): Operating Activities $ 261.0 $342.3 Investing Activities (568.5) (458.1) Financing Activities 236.6 169.5
During the six months ended June 30, 2001, we generated less cash from operations compared to the same period in 2000 mostly because of changes in working capital requirements. During the six months ended June 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 six months ended June 30, 2001, we had more cash from financing activities compared to the same period of 2000 mostly because we issued more common stock, short-term borrowings, and long-term debt. We also decreased our payment of dividends. 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- "a2" A-
Upon separation of our merchant energy business, the merchant energy business and BGE Corp. will be rated separately. The ratings for these entities at separation could differ from Constellation Energy's current ratings. However, we expect the new ratings to be investment grade. We do not expect BGE's ratings to be negatively impacted by the separation. 31 Capital Resources - ----------------- Our business requires a great deal of capital. Our estimated annual amounts for the years 2001 through 2003, are shown in the table below. 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 through 2003 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 below 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 development, 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 37.
Calendar Year Estimates 2001 2002 2003 - ------------------------------------------------------------------ --------- -------- -------- (In millions) Nonregulated Capital Requirements: Investment requirements: Domestic merchant energy $1,402 $ 739 $1,540 Other 39 79 105 - ------------------------------------------------------------------ --------- --------- -------- Total investment requirements 1,441 818 1,645 Retirement of long-term debt 914* 684 209 - ------------------------------------------------------------------ --------- --------- -------- Total nonregulated capital requirements 2,355 1,502 1,854 Utility Capital Requirements: Construction expenditures: Regulated electric 163 171 173 Regulated gas 53 52 52 Common 30 26 20 - ------------------------------------------------------------------ --------- --------- -------- Total capital expenditures 246 249 245 Retirement of long-term debt and redemption of preference stock 394 520 286 - ------------------------------------------------------------------ --------- --------- -------- Total utility capital requirements 640 769 531 - ------------------------------------------------------------------ --------- --------- -------- Total capital requirements $2,995 $2,271 $2,385 ================================================================== ========= ========= ========
* Amount does not include $1.1 billion in Constellation Energy debt that we expect to be redeemed at or prior to business separation 32 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 investment requirements include the planned acquisition of the Nine Mile Point nuclear power plant and 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. An additional 6,000 megawatts of peaking and combined cycle production facilities are scheduled for completion in 2002 and beyond in various regions of North America. For further information see the Strategy section on page 19. Our domestic merchant energy business investment requirements also include construction expenditures for improvements to existing 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 $ 83 million in 2001, o $ 59 million in 2002, and o $ 7 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 14. Regulated Electric and Gas - -------------------------- Regulated electric and gas construction expenditures primarily include new business construction needs and improvements to existing facilities. Funding for Capital Requirements - -------------------------------- On October 23, 2000, we announced initiatives designed to advance our growth strategies in the domestic merchant energy business and a change in our common stock dividend policy effective April 2001, as discussed in the Strategy section on page 19. As part of these initiatives, we expect to redeem all of the outstanding debt at Constellation Energy at or prior to the separation of our domestic merchant energy business and remaining businesses. The redemption will occur through a combination of open market purchases, tender offers, and redemption calls. In June, 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 13. Prior to or upon separation, new Constellation Energy will assume these facilities. 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, one-half of the purchase price is due at the closing of the transaction 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 expect to close the transaction with funds from available sources at that time. Payments on the note over the five years are expected to come from internally generated funds. 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. When our domestic merchant energy business separates from our remaining businesses, it initially expects to reinvest its earnings to fund its growth and not to pay a dividend. 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 13. In addition, Constellation Energy has access to interim lines of credit as required from time to time to support its outstanding commercial paper. 33 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. At March 31, 2001, FERC authorized BGE to issue up to $700 million of short-term borrowings, including commercial paper. In addition, BGE maintains $193 million in annual committed bank lines of credit and has $25 million in bank revolving credit agreements to support the commercial paper program. In addition, BGE has access to interim lines of credit as required from time to time to support its outstanding commercial paper. During the three years from 2001 through 2003, we expect our regulated utility business to provide at least 130% 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 may meet 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, Latin American operation, 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 30. - -------------------------------------------------------------------------------- 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 13 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 16. - -------------------------------------------------------------------------------- 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 20, o financing activities and an accounting standard adopted in the Notes to Consolidated Financial Statements on pages 13 and 16, and o activities of our power marketing business in the Domestic Merchant Energy Business section of Management's Discussion and Analysis beginning on page 25. 34 PART II. OTHER INFORMATION - --------------------------- Item 1. Legal Proceedings - -------------------------- 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. 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 541 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, o and the date on which the exposure allegedly occurred. To date, 34 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. 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 350 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. 35 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. 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. 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. - -------------------------------------------------------------------------------- Item 4. Submission of Matters to a Vote of Security Holders - ------------------------------------------------------------ On April 27, 2001, Constellation Energy Group held its annual meeting of shareholders. At that meeting, the following matters were voted upon: 1. All of the Directors nominated by Constellation Energy Group were selected as follows:
COMMON SHARES CAST: ------------------ For Against Abstain --- ------- ------- H. Furlong Baldwin 130,910,754 651,886 2,056,959 James T. Brady 131,016,627 546,014 2,056,959 Beverly B. Byron 130,632,602 930,038 2,056,959 James R. Curtiss 130,664,970 897,670 2,056,959 Jerome W. Geckle 130,763,903 798,737 2,056,959 George L. Russell 130,676,059 886,582 2,056,959
All other directors whose term of office continues as of the date of this meeting: Douglas L. Becker Robert J. Hurst J. Owen Cole Nancy Lampton Dan A. Colussy Adm. Charles R. Larson Edward A. Crooke Christian H. Poindexter Roger W. Gale Mayo A. Shattuck, III Dr. Freeman A. Hrabowski, III Michael D. Sullivan 2. The ratification of PricewaterhouseCoopers, LLP as independent accountants was approved. With respect to holders of common stock, the number of affirmative votes cast were 127,922,255, the number of negative votes cast were 4,799,834, and the number of abstentions were 1,295,740. 3. The shareholder proposal concerning confidential voting. With respect to holders of common stock, the number of affirmative votes cast were 50,401,683, the number of negative votes cast were 63,781,894, and the number of abstentions were 3,420,410. 4. The shareholder proposal concerning investing in clean energy. With respect to holders of common stock, the number of affirmative votes cast were 6,537,705, the number of negative votes cast were 106,436,367, and the number of abstentions were 4,630,852. 36 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 satisfaction of all the conditions precedent to the closing on the purchase of the Nine Mile Point nuclear power plants, including obtaining all regulatory approvals, o obtaining all regulatory approvals necessary to close on the investment by an affiliate of the Goldman Sachs Group, Inc. in our domestic merchant energy business and complete the separation of our domestic merchant energy business from our remaining businesses, o satisfaction of all conditions precedent to the transaction with Goldman Sachs, o general economic, business, and regulatory conditions, o the pace and nature of deregulation nationwide (including the status of the California markets), o competition, o energy supply and demand, o federal and state regulations, o availability, terms, and use of capital, o nuclear and environmental issues, o weather, o implications of the Restructuring Order issued by the Maryland PSC, including the outcome of the appeal, o commodity price risk, o operating our generation assets in a deregulated market without the benefit of a fuel rate adjustment clause, o loss of revenue due to customers choosing alternative suppliers, o higher volatility of earnings and cash flows, o increased financial requirements of our nonregulated subsidiaries, o inability to recover all costs associated with providing electric retail customers service during the electric rate freeze period, o implications from the transfer of BGE's generation assets and related liabilities to nonregulated subsidiaries of Constellation Energy, including the outcome of an appeal of the Maryland PSC's Order regarding the transfer of generation assets, and o force majeure (events beyond our control), or other unforeseen events or delays, such as: acts of nature, changes of laws, labor strikes, work stoppages, and resource shortages, especially as they could impact plant construction or operation. 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. - -------------------------------------------------------------------------------- Item 6. Exhibits and Reports on Form 8-K (a) 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 June 30, 2001: None. 37 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) BALTIMORE GAS AND ELECTRIC COMPANY ----------------------------------- (Registrant) Date: August 13, 2001 /s/ E. Follin Smith -------------- ----------------------------------- E. Follin Smith, Senior Vice President on behalf of Constellation Energy Group, Inc. and as Principal Financial Officer Date: August 13, 2001 /s/ Thomas F. Brady -------------- ----------------------------------- Thomas F. Brady, on behalf of Baltimore Gas and Electric Company as Principal Financial Officer EX-12 4 ex12a.txt EXHIBIT 12A EXHIBIT 12(a) CONSTELLATION ENERGY GROUP, INC. AND SUBSIDIARIES ------------------------------------------------- COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES
12 Months Ended --------------------------------------------------------------------------------- June December December December December December 2001 2000 1999 1998 1997 1996 ------ -------- -------- -------- -------- -------- (In Millions of Dollars) Income from Continuing Operations (Before Extraordinary Loss and Cumulative Effect of Change in Accounting Principle) $ 412.5 $ 345.3 $ 326.4 $ 305.9 $ 254.1 $ 272.3 Taxes on Income, Including Tax Effect for BGE Preference Stock Dividends 249.2 221.4 182.5 169.3 145.1 148.3 ------ -------- -------- -------- -------- -------- Adjusted Income $ 661.7 $ 566.7 $ 508.9 $ 475.2 $ 399.2 $ 420.6 ------ -------- -------- -------- -------- -------- Fixed Charges: Interest and Amortization of Debt Discount and Expense and Premium on all Indebtedness $ 250.6 $ 261.5 $ 245.7 $ 255.3 $ 234.2 $ 203.9 Earnings required for BGE Preference Stock Dividends 22.2 21.9 21.0 33.8 45.1 59.4 Capitalized Interest 36.4 21.1 2.7 3.6 8.4 15.7 Interest Factor in Rentals 2.0 2.2 1.8 1.9 1.9 1.5 ------ -------- -------- -------- -------- -------- Total Fixed Charges $ 311.2 $ 306.7 $ 271.2 $ 294.6 $ 289.6 $ 280.5 ------ -------- -------- -------- -------- -------- Earnings (1) $ 936.5 $ 852.3 $ 777.4 $ 766.2 $ 680.4 $ 685.4 ====== ======== ======== ======== ======== ======== Ratio of Earnings to Fixed Charges 3.01 2.78 2.87 2.60 2.35 2.44
(1) Earnings are deemed to consist of income from continuing operations (before extraordinary loss and cumulative effect of change in accounting principle) that includes earnings of Constellation Energy's consolidated subsidiaries, equity in the net income of unconsolidated subsidiaries, income taxes (including deferred income taxes, investment tax credit adjustments, and the tax effect of BGE's preference stock dividends), and fixed charges other than capitalized interest. EX-12 5 ex12b.txt EXHIBIT 12B EXHIBIT 12(b) BALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARIES --------------------------------------------------- COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES AND COMPUTATION OF RATIO OF EARNINGS TO COMBINED FIXED CHARGES AND PREFERRED AND PREFERENCE DIVIDEND REQUIREMENTS
12 Months Ended --------------------------------------------------------------------------------- June December December December December December 2001 2000 1999 1998 1997 1996 ------ -------- -------- -------- -------- -------- (In Millions of Dollars) Income from Continuing Operations (Before Extraordinary Loss) $ 118.4 $ 143.5 $ 328.4 $ 327.7 $ 282.8 $ 310.8 Taxes on Income 80.6 94.2 182.0 181.3 161.5 169.2 ------ -------- -------- -------- -------- -------- Adjusted Income $ 199.0 $ 237.7 $ 510.4 $ 509.0 $ 444.3 $ 480.0 ------ -------- -------- -------- -------- -------- Fixed Charges: Interest and Amortization of Debt Discount and Expense and Premium on all Indebtedness $ 172.6 $ 186.8 $ 206.4 $ 255.3 $ 234.2 $ 203.9 Capitalized Interest - - 0.4 3.6 8.4 15.7 Interest Factor in Rentals 0.7 0.9 1.0 1.9 1.9 1.5 ------ -------- -------- -------- -------- -------- Total Fixed Charges $ 173.3 $ 187.7 $ 207.8 $ 260.8 $ 244.5 $ 221.1 ------ -------- -------- -------- -------- -------- Preferred and Preference Dividend Requirements: (1) Preferred and Preference Dividends $ 13.2 $ 13.2 $ 13.5 $ 21.8 $ 28.7 $ 38.5 Income Tax Required 9.0 8.7 7.5 12.0 16.4 20.9 ------ -------- -------- -------- -------- -------- Total Preferred and Preference Dividend Requirements $ 22.2 $ 21.9 $ 21.0 $ 33.8 $ 45.1 $ 59.4 ------ -------- -------- -------- -------- -------- Total Fixed Charges and Preferred and Preference Dividend Requirements $ 195.5 $ 209.6 $ 228.8 $ 294.6 $ 289.6 $ 280.5 ====== ======== ======== ======== ======== ======== Earnings (2) $ 372.3 $ 425.4 $ 717.8 $ 766.2 $ 680.4 $ 685.4 ====== ======== ======== ======== ======== ======== Ratio of Earnings to Fixed Charges 2.15 2.27 3.45 2.94 2.78 3.10 Ratio of Earnings to Combined Fixed Charges and Preferred and Preference Dividend Requirements 1.90 2.03 3.14 2.60 2.35 2.44
(1)Preferred and preference dividend requirements consist of an amount equal to the pre-tax earnings that would be required to meet dividend requirements on preferred stock and preference stock. (2)Earnings are deemed to consist of income from continuing operations (before extraordinary loss) that includes earnings of BGE's consolidated subsidiaries, income taxes (including deferred income taxes and investment tax credit adjustments), and fixed charges other than capitalized interest. -----END PRIVACY-ENHANCED MESSAGE-----