-----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, MCj8CLlCBMq8qcyjTFQMBa7jPUfCoLfuvAiVEpR0lp8dPymqo+idV4o1o+U0U+nu OSR0h9OJM5+Nu4n3CfSRLQ== 0001004440-00-000014.txt : 20000516 0001004440-00-000014.hdr.sgml : 20000516 ACCESSION NUMBER: 0001004440-00-000014 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 6 CONFORMED PERIOD OF REPORT: 20000331 FILED AS OF DATE: 20000515 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: SEC FILE NUMBER: 000-25931 FILM NUMBER: 634641 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 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: SEC FILE NUMBER: 001-01910 FILM NUMBER: 634642 BUSINESS ADDRESS: STREET 1: 39 W LEXINGTON ST STREET 2: CHARLES CTR CITY: BALTIMORE STATE: MD ZIP: 21201 BUSINESS PHONE: 4102345511 10-Q 1 QUARTERLY REPORT 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 MARCH 31, 2000 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) 39 W. LEXINGTON STREET, BALTIMORE, MARYLAND 21201 ---------------------- ----------------------- ---------------- (Former name, former address of Baltimore Gas and Electric Company 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 149,602,816 shares outstanding of Constellation Energy Group, Inc. on April 28, 2000. 1 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 Statements of Comprehensive 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.............................................................. 16 Introduction........................................................................... 16 Strategy............................................................................... 17 Current Issues......................................................................... 17 Results of Operations................................................................. 19 Financial Condition.................................................................... 27 Capital Resources...................................................................... 28 Other Matters.......................................................................... 31 Item 3 -- Quantitative and Qualitative Disclosures About Market Risk............................. 31 Part II -- Other Information Item 1 -- Legal Proceedings...................................................................... 32 Item 5 -- Other Information...................................................................... 33 Item 6 -- Exhibits and Reports on Form 8-K....................................................... 33 Signature........................................................................................ 34
2 CONSTELLATION ENERGY GROUP, INC. AND SUBSIDIARIES PART I - FINANCIAL INFORMATION Item 1 - Financial Statements Consolidated Statements of Income (Unaudited)
Three Months Ended March 31, ---------------------------- 2000 1999 ------------- ------------- (In Millions, Except Per-Share Amounts) Revenues Electric $ 524.4 $ 513.0 Gas 194.5 192.8 Nonregulated 273.3 277.6 ------------- ------------- Total revenues 992.2 983.4 Operating Expenses Electric fuel and purchased energy 118.6 121.1 Gas purchased for resale 102.9 102.1 Operations 134.3 135.3 Maintenance 45.1 48.9 Nonregulated - selling, general, and administrative 214.9 227.4 Depreciation and amortization 132.5 90.3 Taxes other than income taxes 61.1 60.2 ------------- ------------- Total operating expenses 809.4 785.3 ------------- ------------- Income From Operations 182.8 198.1 Other Income (Expense) 5.0 (0.8) ------------- ------------- Income Before Fixed Charges and Income Taxes 187.8 197.3 Fixed Charges Interest expense (net) 60.4 61.2 BGE preference stock dividends 3.3 3.4 ------------- ------------- Total fixed charges 63.7 64.6 ------------- ------------- Income Before Income Taxes 124.1 132.7 Income Taxes Current 61.2 49.6 Deferred (7.1) 2.5 Investment tax credit adjustments (2.1) (2.2) ------------- ------------- Total income taxes 52.0 49.9 ------------- ------------- Net Income $ 72.1 $ 82.8 ============= ============= Earnings Applicable to Common Stock $ 72.1 $ 82.8 ============= ============= Average Shares of Common Stock Outstanding 149.6 149.5 Earnings Per Common Share and Earnings Per Common Share - Assuming Dilution $0.48 $0.55 Dividends Declared Per Common Share $0.42 $0.42 Consolidated Statements of Comprehensive Income (Unaudited) Three Months Ended March 31, ---------------------------- 2000 1999 ------------- ------------- (In Millions) Net Income $ 72.1 $ 82.8 Other comprehensive income (loss), net of taxes 13.0 (3.2) ------------- ------------- Comprehensive Income $ 85.1 $ 79.6 ============= =============
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 I - FINANCIAL INFORMATION (CONTINUED) Item 1 - Financial Statements Consolidated Balance Sheets
March 31, December 31, 2000* 1999 ------------- ------------- (In Millions) Assets Current Assets Cash and cash equivalents $ 68.2 $ 92.7 Accounts receivable (net of allowance for uncollectibles of $22.0 and $34.8 respectively) 455.2 578.5 Trading securities 161.4 136.5 Assets from energy trading activities 448.3 312.1 Fuel stocks 69.6 94.9 Materials and supplies 148.5 149.1 Prepaid taxes other than income taxes 33.9 72.4 Other 36.9 54.0 ------------- ------------- Total current assets 1,422.0 1,490.2 Investments and Other Assets Real estate projects and investments 305.3 310.1 Power projects 820.2 785.4 Financial investments 169.4 145.4 Nuclear decommissioning trust fund 222.7 217.9 Net pension asset 95.5 99.5 Other 432.3 422.9 ------------- ------------- Total investments and other assets 2,045.4 1,981.2 Utility Plant Plant in service Electric 7,123.4 7,088.6 Gas 970.2 962.0 Common 562.2 569.5 ------------- ------------- Total plant in service 8,655.8 8,620.1 Accumulated depreciation (3,522.1) (3,466.1) ------------- ------------- Net plant in service 5,133.7 5,154.0 Construction work in progress 241.1 222.3 Nuclear fuel (net of amortization) 123.4 133.8 Plant held for future use 12.9 13.0 ------------- ------------- Net utility plant 5,511.1 5,523.1 Deferred Charges Regulatory assets (net) 580.4 637.4 Other 68.7 51.9 ------------- ------------- Total deferred charges 649.1 689.3 ------------- ------------- Total Assets $ 9,627.6 $ 9,683.8 ============= =============
* Unaudited See Notes to Consolidated Financial Statements. 4 CONSTELLATION ENERGY GROUP, INC. AND SUBSIDIARIES PART I - FINANCIAL INFORMATION (CONTINUED) Item 1 - Financial Statements Consolidated Balance Sheets
March 31, December 31, 2000* 1999 ------------- ------------- (In Millions) Liabilities and Capitalization Current Liabilities Short-term borrowings $ 339.8 $ 371.5 Current portion of long-term debt 797.9 808.3 Accounts payable 280.7 365.1 Customer deposits 41.6 40.6 Liabilities from energy trading activities 257.3 163.8 Dividends declared 66.1 66.1 Accrued taxes 75.8 19.2 Accrued interest 57.7 55.3 Accrued vacation costs 36.1 35.3 Other 43.6 78.2 ------------- ------------- Total current liabilities 1,996.6 2,003.4 Deferred Credits and Other Liabilities Deferred income taxes 1,287.5 1,288.8 Postretirement and postemployment benefits 268.3 269.8 Deferred investment tax credits 107.5 109.6 Decommissioning of federal uranium enrichment facilities 27.2 27.2 Other 244.3 226.6 ------------- ------------- Total deferred credits and other liabilities 1,934.8 1,922.0 Long-term Debt First refunding mortgage bonds of BGE 1,321.7 1,321.7 Other long-term debt of BGE 1,068.9 1,135.8 Company obligated mandatorily redeemable trust preferred securities of subsidiary trust holding solely 7.16% debentures of BGE 250.0 250.0 Long-term debt of nonregulated businesses 655.5 686.8 Unamortized discount and premium (10.1) (10.6) Current portion of long-term debt (797.9) (808.3) ------------- ------------- Total long-term debt 2,488.1 2,575.4 BGE Preference Stock Not Subject to Mandatory Redemption 190.0 190.0 Common Shareholders' Equity Common stock 1,496.8 1,494.0 Retained earnings 1,508.4 1,499.1 Accumulated other comprehensive income (loss) 12.9 (0.1) ------------- ------------- Total common shareholders' equity 3,018.1 2,993.0 ------------- ------------- Total capitalization 5,696.2 5,758.4 ------------- ------------- Total Liabilities and Capitalization $ 9,627.6 $ 9,683.8 ============= =============
* Unaudited See Notes to Consolidated Financial Statements. 5 CONSTELLATION ENERGY GROUP, INC. AND SUBSIDIARIES PART I - FINANCIAL INFORMATION (CONTINUED) Item 1 - Financial Statements Consolidated Statements of Cash Flows (Unaudited)
Three Months Ended March 31, ----------------------------- 2000 1999 ------------- ------------ (In Millions) Cash Flows From Operating Activities Net income $ 72.1 $ 82.8 Adjustments to reconcile to net cash provided by operating activities Depreciation and amortization 146.7 104.7 Deferred income taxes (7.1) 2.5 Investment tax credit adjustments (2.1) (2.2) Deferred fuel costs 1.6 7.6 Accrued pension and postemployment benefits 8.7 16.2 Equity in earnings of affiliates and joint ventures (net) 3.1 22.5 Changes in assets from energy trading activities (136.2) (12.6) Changes in liabilities from energy trading activities 93.5 (10.9) Changes in other current assets 99.1 36.7 Changes in other current liabilities 28.7 74.3 Other (10.1) (4.1) ------------- ------------ Net cash provided by operating activities 298.0 317.5 ------------- ------------ Cash Flows From Investing Activities Utility construction and other capital expenditures (80.6) (75.3) Contributions to nuclear decommissioning trust fund (4.4) (4.4) Purchases of marketable equity securities (25.7) (7.8) Sales of marketable equity securities 17.9 4.2 Other financial investments 9.4 5.5 Real estate projects and investments 3.9 26.1 Power projects (40.8) (5.5) Other (7.7) (10.4) ------------- ------------ Net cash used in investing activities (128.0) (67.6) ------------- ------------ Cash Flows From Financing Activities Proceeds from issuance of Short-term borrowings 2,533.3 523.5 Long-term debt - 104.6 Common stock 1.5 9.6 Repayments of short-term borrowings (2,565.0) (523.5) Reacquisitions of long-term debt (98.2) (128.8) Common stock dividends paid (62.8) (62.7) Other (3.3) (2.3) ------------- ------------ Net cash used in financing activities (194.5) (79.6) ------------- ------------ Net (Decrease) Increase in Cash and Cash Equivalents (24.5) 170.3 Cash and Cash Equivalents at Beginning of Period 92.7 173.7 ------------- ------------ Cash and Cash Equivalents at End of Period $ 68.2 $ 344.0 ============= ============ Other Cash Flow Information: Interest paid (net of amounts capitalized) $ 62.4 $ 51.6 Income taxes paid $ 8.0 $ 1.0
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 I - FINANCIAL INFORMATION Item 1 - Financial Statements Consolidated Statements of Income (Unaudited)
Three Months Ended March 31, ---------------------------- 2000 1999 ------------- ------------- (In Millions) Revenues Electric $ 524.6 $ 513.0 Gas 195.1 192.8 Nonregulated 1.0 277.6 ------------- ------------- Total revenues 720.7 983.4 Operating Expenses Electric fuel and purchased energy 119.4 121.1 Gas purchased for resale 103.0 102.1 Operations 132.9 135.3 Maintenance 44.7 48.9 Nonregulated - selling, general, and administrative 0.6 227.4 Depreciation and amortization 126.1 90.3 Taxes other than income taxes 60.1 60.2 ------------- ------------- Total operating expenses 586.8 785.3 ------------- ------------- Income From Operations 133.9 198.1 Other Income (Expense) Allowance for equity funds used during construction 0.7 1.7 Equity in earnings of Safe Harbor Water Power Corporation 1.2 1.3 Net other expense 1.4 (3.8) ------------- ------------- Total other income (expense) 3.3 (0.8) ------------- ------------- Income Before Fixed Charges and Income Taxes 137.2 197.3 Fixed Charges Interest expense (net) 48.7 62.4 Capitalized interest - (0.3) Allowance for borrowed funds used during construction (1.2) (0.9) ------------- ------------- Total fixed charges 47.5 61.2 ------------- ------------- Income Before Income Taxes 89.7 136.1 Income Taxes Current 57.8 49.6 Deferred (20.3) 2.5 Investment tax credit adjustments (2.0) (2.2) ------------- ------------- Total income taxes 35.5 49.9 ------------- ------------- Net Income 54.2 86.2 Preference Stock Dividends 3.3 3.4 ------------- ------------- Earnings Applicable to Common Stock $ 50.9 $ 82.8 ============= ============= Consolidated Statements of Comprehensive Income (Unaudited) Three Months Ended March 31, ---------------------------- 2000 1999 ------------- ------------- (In Millions) Net Income $ 54.2 $ 86.2 Other comprehensive income (loss), net of taxes - (3.2) ------------- ------------- Comprehensive Income $ 54.2 $ 83.0 ============= =============
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 I - FINANCIAL INFORMATION (CONTINUED) Item 1 - Financial Statements Consolidated Balance Sheets
March 31, December 31, 2000* 1999 -------------- --------------- (In Millions) Assets Current Assets Cash and cash equivalents $ 20.0 $ 23.5 Accounts receivable (net of allowance for uncollectibles of $13.0 and $13.0 respectively) 294.8 316.1 Fuel stocks 69.6 94.9 Materials and supplies 138.6 139.1 Prepaid taxes other than income taxes 33.9 72.4 Other 7.2 9.0 -------------- --------------- Total current assets 564.1 655.0 Investments and Other Assets Nuclear decommissioning trust fund 222.7 217.9 Net pension asset 99.3 99.8 Safe Harbor Water Power Corporation 34.5 34.5 Other 62.6 61.6 -------------- --------------- Total investments and other assets 419.1 413.8 Utility Plant Plant in service Electric 7,123.4 7,088.6 Gas 970.2 962.0 Common 562.2 569.5 -------------- --------------- Total plant in service 8,655.8 8,620.1 Accumulated depreciation (3,522.1) (3,466.1) -------------- --------------- Net plant in service 5,133.7 5,154.0 Construction work in progress 241.1 222.3 Nuclear fuel (net of amortization) 123.4 133.8 Plant held for future use 12.9 13.0 -------------- --------------- Net utility plant 5,511.1 5,523.1 Deferred Charges Regulatory assets (net) 580.4 637.4 Other 59.4 43.3 -------------- --------------- Total deferred charges 639.8 680.7 -------------- --------------- Total Assets $ 7,134.1 $ 7,272.6 ============== ===============
* Unaudited See Notes to Consolidated Financial Statements. 8 BALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARIES PART I - FINANCIAL INFORMATION (CONTINUED) Item 1 - Financial Statements Consolidated Balance Sheets
March 31, December 31, 2000* 1999 -------------- --------------- (In Millions) Liabilities and Capitalization Current Liabilities Short-term borrowings $ 88.6 $ 129.0 Current portion of long-term debt 543.9 523.9 Accounts payable 190.3 222.8 Customer deposits 41.6 40.6 Dividends declared 3.3 3.3 Accrued taxes 69.3 9.2 Accrued interest 43.2 48.2 Accrued vacation costs 36.7 35.7 Other 36.8 65.8 -------------- --------------- Total current liabilities 1,053.7 1,078.5 Deferred Credits and Other Liabilities Deferred income taxes 1,010.4 1,032.0 Postretirement and postemployment benefits 240.5 231.0 Deferred investment tax credits 107.5 109.6 Decommissioning of federal uranium enrichment facilities 27.2 27.2 Other 41.4 42.9 -------------- --------------- Total deferred credits and other liabilities 1,427.0 1,442.7 Long-term Debt First refunding mortgage bonds of BGE 1,321.7 1,321.7 Other long-term debt of BGE 1,068.9 1,135.8 Company obligated mandatorily redeemable trust preferred securities of subsidiary trust holding solely 7.16% debentures of BGE 250.0 250.0 Long-term debt of nonregulated businesses 32.0 33.0 Unamortized discount and premium (10.1) (10.6) Current portion of long-term debt (543.9) (523.9) -------------- --------------- Total long-term debt 2,118.6 2,206.0 Preference Stock Not Subject to Mandatory Redemption 190.0 190.0 Common Shareholder's Equity Common stock 1,495.3 1,494.0 Retained earnings 849.5 861.4 -------------- --------------- Total common shareholder's equity 2,344.8 2,355.4 -------------- --------------- Total capitalization 4,653.4 4,751.4 -------------- --------------- Total Liabilities and Capitalization $ 7,134.1 $ 7,272.6 ============== ===============
* Unaudited See Notes to Consolidated Financial Statements. 9 BALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARIES PART I - FINANCIAL INFORMATION (CONTINUED) Item 1 - Financial Statements Consolidated Statements of Cash Flows (Unaudited)
Three Months Ended March 31, --------------------------------- 2000 1999 -------------- -------------- (In Millions) Cash Flows From Operating Activities Net income $ 54.2 $ 86.2 Adjustments to reconcile to net cash provided by operating activities Depreciation and amortization 137.9 104.7 Deferred income taxes (20.3) 2.5 Investment tax credit adjustments (2.0) (2.2) Deferred fuel costs 1.6 7.6 Accrued pension and postemployment benefits 8.6 16.2 Allowance for equity funds used during construction (0.7) (1.7) Equity in earnings of affiliates and joint ventures (net) - 22.5 Changes in assets from energy trading activities - (12.6) Changes in liabilities from energy trading activities - (10.9) Changes in other current assets 87.4 36.7 Changes in other current liabilities (4.4) 74.3 Other (6.7) (2.4) -------------- -------------- Net cash provided by operating activities 255.6 320.9 -------------- -------------- Cash Flows From Investing Activities Utility construction expenditures (including AFC) (79.8) (73.4) Allowance for equity funds used during construction 0.7 1.7 Nuclear fuel expenditures (0.7) (1.6) Deferred energy conservation expenditures (0.1) (0.3) Contributions to nuclear decommissioning trust fund (4.4) (4.4) Purchases of marketable equity securities - (7.8) Sales of marketable equity securities - 4.2 Other financial investments - 5.5 Real estate projects and investments - 26.1 Power projects - (5.5) Other (1.7) (12.1) -------------- -------------- Net cash used in investing activities (86.0) (67.6) -------------- -------------- Cash Flows From Financing Activities Proceeds from issuance of Short-term borrowings 1,118.3 523.5 Long-term debt - 104.6 Common stock - 9.6 Repayments of short-term borrowings (1,158.7) (523.5) Reacquisition of long-term debt (67.9) (128.8) Common stock dividends paid (62.8) (62.7) Preference stock dividends paid (3.3) (3.4) Other 1.3 (2.3) -------------- -------------- Net cash used in financing activities (173.1) (83.0) -------------- -------------- Net (Decrease) Increase in Cash and Cash Equivalents (3.5) 170.3 Cash and Cash Equivalents at Beginning of Period 23.5 173.7 -------------- -------------- Cash and Cash Equivalents at End of Period $ 20.0 $ 344.0 ============== ============== Other Cash Flow Information: Interest paid (net of amounts capitalized) $ 52.6 $ 51.6 Income taxes paid $ 6.5 $ 1.0
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 Constellation(R) Enterprises, Inc. Constellation Enterprises was previously owned by BGE. 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. 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. As Constellation Enterprises and its subsidiaries were subsidiaries of BGE prior to April 30, 1999, they are included in the consolidated financial statements of BGE through that date. 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. We discuss the Restructuring Order further in the Electric Restructuring section of Management's Discussion and Analysis on page 20. Information by Operating Segment - -------------------------------- In 1999, we reported three operating segments -- Electric, Gas, and Energy Services. In response to the deregulation of electric generation, we are realigning our organization, combining our wholesale power marketing business with our domestic plant development and operations to form a merchant energy business. In 2000, we revised our operating segments to reflect the recent and anticipated realignments of our organization. Our new reportable operating segments are -- Regulated Electric, Regulated Gas, and Domestic Wholesale Energy. We have restated certain prior period information for comparative purposes based on our new reportable operating segments. o Our regulated electric business generates, purchases, and sells electricity in a regulated environment, o Our regulated gas business purchases, transports, and sells natural gas in a regulated environment, and o Our nonregulated domestic wholesale energy business: - develops, owns, and operates domestic power projects, - provides power marketing and risk management services, and - provides nuclear consulting services. 11 Until July 1, 2000, the financial results of the electric generation portion of our business will be included in our regulated electric segment. However, at that date, we will include the financial results of electric generation in the domestic wholesale energy segment. Our remaining nonregulated businesses: o develop, own, and operate international power projects, 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.
Domestic Regulated Regulated Wholesale Other Unallocated Electric Gas Energy Nonregulated Corporate Business Business Business Businesses Items (a) Eliminations Consolidated ------------ ------------ ------------- --------------- -------------- ------------- --------------- For the three months ended March 31, (in millions) 2000 - ---- Unaffiliated revenues $ 524.4 $ 194.5 $ 90.9 $ 182.4 $ - $ - $ 992.2 Intersegment revenues 0.2 0.6 - 6.7 - (7.5) - ---------- ------------- ------------- --------------- -------------- ------------- --------------- Total revenues 524.6 195.1 90.9 189.1 - (7.5) 992.2 Net income 30.8 20.3 19.2 1.8 - - 72.1 1999 - ---- Unaffiliated revenues $ 513.0 $ 192.8 $ 56.2 $ 221.4 $ - $ - $ 983.4 Intersegment revenues 0.4 2.1 - 0.6 - (3.1) - ---------- ------------- ------------- --------------- -------------- ------------- --------------- Total revenues 513.4 194.9 56.2 222.0 - (3.1) 983.4 Net income 46.4 21.6 14.0 0.5 - 0.3 82.8 At March 31, 2000 - ----------------- Segment assets $6,193.8 896.4 1,322.4 1,247.8 (6.5) (26.3) $9,627.6 At December 31, 1999 - -------------------- Segment assets $6,312.6 915.3 1,206.1 1,226.7 37.0 (13.9) $9,683.8
(a) We do not allocate certain items presented in the table for Constellation Energy Group and a holding company for our nonregulated businesses. 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, 2000 through the date of this report, we issued a total of 146,400 shares of common stock, without par value, under our Continuous Offering Program for Stock. Net proceeds were about $5.0 million. Constellation Energy issued the following medium-term notes during the period from January 1, 2000 through the date of this report: Date Net Principal Issued Proceeds --------- ------ -------- (In millions) 7 7/8% Notes due 2005 $300 4/00 $297.5 Floating Rate Notes due 2003 200 4/00 199.3 12 In June 1999, Constellation Energy arranged a $135 million revolving credit agreement for short-term financial needs, including letters of credit. As of the date of this report, letters of credit totaling $23.9 million were issued under this facility. Also, letters of credit totaling $5.2 million were issued under another line of credit. Constellation Energy has issued guarantees in an amount up to $99.7 million related to credit facilities and contractual performance of certain of its nonregulated subsidiaries. However, the actual subsidiary liabilities related to these guarantees totaled $33.0 million at March 31, 2000. BGE and Nonregulated Businesses - ------------------------------- Please refer to the Funding for Capital Requirements section of Management's Discussion and Analysis on page 30 for information about the debt of BGE and our nonregulated businesses. 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, including the mix of secured and unsecured debt. Commitments - ----------- Some of our nonregulated businesses have committed to contribute additional capital and to make additional loans to some affiliates, joint ventures, and partnerships in which they have an interest. At the date of this report, the total amount of investment requirements committed to by our nonregulated businesses was $213.6 million. This amount includes $19.5 million for our domestic wholesale energy business' remaining commitment to Orion Power Holdings, Inc. To date, our domestic wholesale energy business has funded $205.5 in equity to Orion. Environmental Matters - --------------------- Clean Air - --------- The Clean Air Act of 1990 contains two titles designed to reduce emissions of sulfur dioxide and nitrogen oxide (NOx) from electric generating stations - Title IV and Title I. Title IV addresses emissions of sulfur dioxide. Compliance is required in two phases: o Phase I became effective January 1, 1995. We met the requirements of this phase by installing flue gas desulfurization systems, switching fuels, and retiring some units. o Phase II became effective January 1, 2000. We met the compliance requirements through a combination of switching fuels and allowance trading. We will meet the ongoing compliance requirements through a combination of switching fuels and allowance trading. Title I addresses emissions of NOx. The Maryland Department of the Environment (MDE) issued regulations, effective October 18, 1999, which required up to 65% NOx emissions reductions by May 1, 2000. We entered into a settlement agreement with the MDE since we could not meet this deadline. Under the terms of the settlement agreement, BGE will install emissions reduction equipment at two sites by May 2002. In the meantime, we are taking steps to control NOx emissions at our generating plants. The Environmental Protection Agency (EPA) issued a final rule in September 1998 that required up to 85% NOx emissions reduction by 22 states including Maryland and Pennsylvania. Maryland expects to meet the requirements of the rule by 2003. The emissions reduction equipment installations discussed above will allow us to meet these requirements. We currently estimate that the controls needed at our generating plants to meet the MDE's 65% NOx emission reduction requirements will cost approximately $135 million. Through the date of this report, we have spent approximately $60 million to meet the 65% reduction requirements. We estimate the additional cost for the EPA's 85% reduction requirements to be approximately $35 million by the end of 2002. 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 is expected to appeal the 1999 court rulings to the Supreme Court. While these standards may require increased controls at our fossil generating plants in the future, implementation, if required, would be delayed for several years. We cannot estimate the cost of these increased controls at this time because the states, including Maryland and Pennsylvania, still need to determine what reductions in pollutants will be necessary to meet the EPA standards. 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. 13 We can, however, estimate that our current 15.43% 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 $4.9 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. On July 12, 1999, the EPA notified us, along with nineteen other entities, that we may be a potentially responsible party at the 68th Street Dump/Industrial Enterprises Site, also known as the Robb Tyler Dump located in Baltimore, Maryland. The EPA indicated that it is proceeding with plans to conduct a remedial investigation and feasibility study. This site was proposed for listing as a federal Superfund site in January 1999, but the listing has not been finalized. Although our potential liability cannot be estimated, we do not expect such liability to be material based on our records showing that we did not send waste to the site. 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 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. We discuss this further in Note 5 of our 1999 Annual Report on Form 10-K. Through the date of this report, we have spent approximately $34 million for remediation at this site. We are also required by accounting rules to disclose additional costs we consider to be less likely than probable, but still "reasonably possible" of being incurred at these sites. 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 do not expect the cleanup costs of the remaining sites to have a material effect on our financial results. Our potential environmental liabilities and pending environmental actions are described further in our 1999 Annual Report on Form 10-K in Item 1. Business - Environmental Matters. Nuclear Insurance - ----------------- If there were 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 $19.1 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 14 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 eight 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 polices exceed the coverage limits, the provisions of the Price Anderson Act (discussed in this section) would apply. Recoverability of Electric Fuel Costs - ------------------------------------- Until July 1, 2000, we will continue to recover our cost of fuel and purchased energy through the electric fuel rate as long as the Maryland PSC finds that, among other things, we have kept the productive capacity of our generating plants at a reasonable level. To do this, the Maryland PSC will evaluate the performance of our generating plants, and will determine if we used all reasonable and cost-effective maintenance and operating control procedures. We discuss this further in Note 10 of our 1999 Annual Report on Form 10-K. The two units at Calvert Cliffs use the cheapest fuel. As a result, the costs of replacement energy associated with outages at these units can be significant. We cannot estimate the amount of replacement energy costs that could be challenged or disallowed in future fuel rate proceedings, but such amounts could be material. Under the terms of the Restructuring Order, BGE's electric fuel rate clause will be discontinued effective July 1, 2000. Any accumulated difference between our actual costs of fuel and energy and the amounts collected from customers under the electric fuel rate clause will be collected from our customers over a period to be determined by the Maryland PSC. At March 31, 2000, the amount to be collected from customers was $60.3 million. California Power Purchase Agreements - ------------------------------------ Constellation Power, Inc. and subsidiaries and Constellation Investments, Inc. (whose power projects are managed by Constellation Power) have $295.8 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 projects supply electricity to utility companies at: o a fixed rate for capacity and energy for the first 10 years of the agreements, and o a fixed rate for capacity plus a variable rate for energy based on the utilities' avoided cost for the remaining term of the agreements. Generally, a "capacity rate" is paid to a power plant for its availability to supply electricity, and an "energy rate" is paid for the electricity actually generated. "Avoided cost" generally is the cost of a utility's cheapest next-available source of generation to service the demands on its system. We use the term "transitioned" to describe when the 10-year periods for fixed energy rates have expired for these power generation projects and they began supplying electricity at variable rates. The three remaining projects that have not transitioned will do so by December 2000. The projects that have already transitioned to variable rates have had lower revenues under variable rates than they did under fixed rates. Once the remaining projects have transitioned to variable rates, we expect the revenues from those projects also to be lower than they are under fixed rates. We discuss the earnings for these projects in the Nonregulated Businesses section of Management's Discussion and Analysis on page 26. Other Nonregulated Businesses - ----------------------------- We discuss our other nonregulated businesses' activities further in the Nonregulated Businesses section of Management's Discussion and Analysis on page 26. 15 Item 2. Management's Discussion Management's Discussion and Analysis of Financial Condition and Results of Operations Introduction - ------------ On April 30, 1999, Constellation Energy(R) Group, Inc. (Constellation Energy) became the holding company for Baltimore Gas and Electric Company (BGE(R)) and Constellation(R) Enterprises, Inc. Constellation Enterprises was previously owned by BGE. In response to the deregulation of electric generation, we are realigning our organization, combining our wholesale power marketing business with our domestic plant development and operations to form a merchant energy business. In 2000, we revised our operating segments to reflect the recent and anticipated realignments of our organization, as presented in the Notes to Consolidated Financial Statements on page 11. Constellation Energy's subsidiaries primarily include BGE and a domestic wholesale energy business focused mostly on power marketing and merchant generation in North America. BGE is 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 domestic wholesale energy segment includes the: o wholesale power marketing of Constellation Power Source,(TM)Inc., o domestic power projects of Constellation Power,(TM)Inc., and subsidiaries and Constellation Investments,(TM) Inc., and o nuclear consulting services of Constellation Nuclear,(TM)LLC. Until July 1, 2000, the financial results of the electric generation portion of our business will be included in BGE's regulated electric segment. However, at that date, we will include the financial results of electric generation in the domestic wholesale energy segment. As a result of the deregulation of electric generation, we recently formed two nonregulated subsidiaries, Calvert Cliffs, Inc. and Constellation Generation, Inc. On or about July 1, 2000, and upon receipt of all regulatory approvals, we expect BGE to transfer, at book value, certain generation assets and liabilities to these entities. We will include these entities in our domestic wholesale energy segment. Our remaining nonregulated businesses include the: o international power projects of Constellation Power, Inc., and subsidiaries, o energy products and services of Constellation Energy Source,(TM)Inc., o home products, commercial building systems, and residential and small commercial gas retail marketing of BGE Home Products & Services,(TM)Inc. and subsidiaries, o general partnership, in which BGE is a partner, of District Chilled Water General Partnership (ComfortLink(R)) that provides cooling services for commercial customers in Baltimore, o financial investments of Constellation Investments, Inc., and o real estate and senior-living facilities of Constellation Real Estate Group,(TM)Inc. 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, ComfortLink, and BGE Capital Trust I. As Constellation Enterprises and its subsidiaries were subsidiaries of BGE prior to April 30, 1999, they are included in the consolidated financial statements of BGE through that date. 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. 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 business, 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. 16 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 ended March 31, 2000 and 1999. 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 current rate regulation. Our electric business will change significantly beginning July 1, 2000 as we enter into the retail customer choice for electric generation and our generation assets are transferred to nonregulated subsidiaries of Constellation Energy. Accordingly, the results of operations and financial condition described in this discussion and analysis are not necessarily indicative of future performance. Strategy - -------- The change toward customer choice will significantly impact our business going forward. In response to this change, we regularly evaluate our strategies with two goals in mind: to improve our competitive position, and to anticipate and adapt to regulatory change. Currently, the majority of our earnings are from BGE. In the future, we expect to derive almost two-thirds of our earnings from competitive markets that are not limited by franchise boundaries. While BGE will continue to be regulated and deliver electricity and natural gas through its core distribution business, our growth strategies center on the nonregulated domestic wholesale energy market with the objective of providing new sources of earnings. As a result of our concentration on domestic merchant energy, we decided to exit the international portion of our business in 1999. We expect to complete our exit strategy by the end of 2000. In addition, we might consider one or more of the following strategies: o the complete or partial separation of our transmission and distribution functions, o the construction, purchase, or sale of generation assets, o mergers or acquisitions of utility or non-utility businesses, and o spin-off or sale of one or more businesses. We cannot predict whether any of the strategies described above may actually occur, or what their effect on our financial results or competitive position might be. However, with the shift toward customer choice, competition, and the growth of our nonregulated subsidiaries, various factors will affect our financial results in the future. These factors include, but are not limited to, operating our currently regulated generation assets in a deregulated market beginning July 1, 2000 without the benefit of a fuel rate adjustment clause, the loss of revenues due to customers choosing alternative suppliers, higher volatility of earnings and cash flows, and increased financial requirements of our nonregulated subsidiaries. Please refer to the Forward-Looking Statements section on page 33 for additional factors. Also, these results will not be indicative of the future performance of BGE once BGE transfers all of its generation to nonregulated subsidiaries of Constellation Energy. The impact of such transfer on BGE's financial results will be material. The total assets, liabilities, and common shareholders' equity of Constellation Energy will not change as a result of the transfer. Current Issues - -------------- Competition - Electric - ---------------------- Electric utilities are facing competition on various fronts, including: o the construction of generating units to meet increased demand for electricity, o the sale of electricity in bulk power markets, o competing with alternative energy suppliers, and o electric sales to retail customers. On April 8, 1999, Maryland enacted legislation authorizing customer choice and competition among electric suppliers. In addition, on November 10, 1999, the Maryland PSC issued a Restructuring Order that resolved the major issues surrounding electric restructuring. These matters are discussed further in the Electric Restructuring section on page 20 and in Note 4 of our 1999 Annual Report on Form 10-K. As a result of the deregulation of BGE's electric generation, no earlier than July 1, 2000, and upon receipt of all regulatory approvals, we expect that BGE will transfer, at book value, its nuclear generating assets and its nuclear decommissioning trust fund to Calvert Cliffs, Inc. In addition, we expect that BGE will transfer, at book value, its fossil generating assets and its partial ownership interest in two coal plants and a hydroelectric plant located in Pennsylvania to Constellation Generation, Inc. In total, these generating assets represent 17 about 6,240 megawatts of generation capacity with a total projected net book value at June 30, 2000 of approximately $2.4 billion. As of the date of this report, we have received approvals from the Federal Energy Regulatory Commission (FERC) and the Pennsylvania Public Utility Commission to transfer these assets. We are awaiting approvals from the Nuclear Regulatory Commission (NRC) and the Maryland PSC. Currently, we expect BGE to transfer approximately $47 million to Calvert Cliffs, Inc. and $231 million to Constellation Generation, Inc. of tax-exempt debt related to the transferred assets. Also, Constellation Generation, Inc. will issue approximately $426 million in unsecured promissory notes to BGE. BGE will exclusively use repayments of the notes by Constellation Generation, Inc. to service certain BGE long-term debt. In our 1999 Annual Report on Form 10-K, we reported that BGE would receive approximately $1.1 billion in unsecured promissory notes. However, due to the Internal Revenue Service's determination that the issuance of certain unsecured notes would not qualify as a tax-free transaction, we have reduced the amount of unsecured promissory notes. BGE will also transfer equity associated with the generating assets to Calvert Cliffs, Inc. and Constellation Generation, Inc. The fossil fuel and nuclear fuel inventories, materials and supplies, and certain purchased power contracts of BGE will also be assumed by these subsidiaries. We present pro-forma financial statements for BGE as an exhibit to this Quarterly Report on Form 10-Q (Exhibit 99). The information provided above and in the pro-forma financial statements have been prepared using information available at the date of this report. As a result, certain amounts are preliminary in nature and therefore, are subject to change. Under the Restructuring Order, BGE will provide 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 once customer choice begins July 1, 2000. In addition, the electric fuel rate will be discontinued effective July 1, 2000. Constellation Power Source will provide BGE with the energy and capacity required to meet its standard offer service obligations for the first three years of the transition period. Standard offer service will be competitively bid thereafter. Constellation Power Source will obtain the energy and capacity to supply BGE's standard offer service obligations from Calvert Cliffs Nuclear Power Plant (Calvert Cliffs) and BGE's former fossil plants and purchased power contracts, supplemented with energy purchased from the wholesale energy market as necessary. Our earnings will be exposed to the risks of the competitive wholesale electricity market to the extent that Constellation Power Source has to purchase energy and/or capacity or generate energy to meet obligations to supply power to BGE at market prices or costs, respectively, which may approach or exceed BGE's standard offer service rates. We will also be affected by operational risk, that is, the risk that a generating plant is not available to produce energy when the energy is required. Until July 1, 2000, BGE will continue to recover its cost of fuel and purchased energy through the electric fuel rate as long as the Maryland PSC finds that, among other things, we have kept the productive capacity of our generating plants at a reasonable level. After July 1, 2000, any energy purchased to meet BGE's load commitments will become a cost of doing business in the newly competitive marketplace. Therefore, if BGE provides standard offer service at fixed rates to its customers that do not select an alternative provider as required under the terms of the Restructuring Order, and the load demand exceeds our capacity to supply energy due to a plant outage, Constellation Power Source would be required to purchase additional power in the wholesale energy market. If the price of obtaining energy in the wholesale market exceeds the fixed standard offer service price, our earnings would be adversely affected. Imbalances in demand and supply can occur not only because of plant outages, but also because of transmission constraints or due to extreme temperatures (hot or cold) causing demand to exceed available supply. We cannot estimate the impact of the increased financial risks associated with the transition to customer choice. However, these financial risks could have a material impact on our, and BGE's, financial results. Competition - Gas - ----------------- 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. Early Retirement Program - ------------------------ In recognition of the changing business environment, in 1999 our Board of Directors approved a Targeted Voluntary Special Early Retirement Program (TVSERP) to provide enhanced early retirement benefits to certain eligible participants in targeted jobs that elect to retire on June 1, 2000. 18 In March 2000, BGE recorded approximately $6.3 million for employees electing the program through March 31, 2000. BGE recorded approximately $2.1 million of this amount on its balance sheet as a regulatory asset of its gas business. The remaining $4.2 million related to its electric business was charged to expense. We estimate that we will record an additional $6 million in the second quarter 2000 for the employees that accepted the program subsequent to March 31, 2000, but before April 14, 2000, the closing of the acceptance period. Of this amount, approximately $5 million relates to our electric business and approximately $1 million relates to our gas business. We discuss the impact of the TVSERP on our financial results in the Results of Operations section below. Calvert Cliffs License Extension - -------------------------------- On March 23, 2000, the NRC approved a 20-year license extension for both units of Calvert Cliffs, extending the license for Unit 1 to 2034 and for Unit 2 to 2036. On April 11, 2000 the United States Court of Appeals for the District of Columbia Circuit, in National Whistleblowers Center v. Nuclear Regulatory Commission and Baltimore Gas and Electric Company, upheld the NRC's denial of the Center's motion to intervene in BGE's license renewal proceeding. The NRC had denied the Center's motion to intervene for failing to file timely contentions. Regional Transmission Organizations - ----------------------------------- In December 1999, the 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 an RTO. FERC also identified the minimum characteristics and functions that a transmission entity must satisfy in order to be considered an RTO. According to the Order, 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 the Pennsylvania-New Jersey-Maryland Interconnection (PJM), must make a filing no later than January 15, 2001. That filing must explain the extent to which the transmission entity in which it participates meets the minimum characteristics and functions of an RTO, and either propose to modify the existing institution to the extent necessary to become an RTO, or explain the efforts, obstacles, and plans with respect to conforming to these characteristics and functions. As a member of the PJM, an existing ISO, BGE does not expect to be materially impacted by the Order. However, BGE, along with other members of the PJM, is appealing certain aspects of the Order. We cannot determine the full impact of the Order at this time. Results of Operations for the Quarter Ended March 31, 2000 Compared with the Same Period of 1999 - -------------------------------------------------------------------------------- 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. Overview - -------- Total Earnings Per Share of Common Stock - ---------------------------------------- Quarter Ended March 31 -------------------------- 2000 1999 ------------ ----------- Utility business........... $ .36 $ .45 Nonregulated businesses.... .14 .10 ------------ ------------ Total earnings per share before nonrecurring charge included in operations ............. .50 .55 Nonrecurring charge included in operations: TVSERP.................. (.02) - ------------ ------------ Total earnings per $ .48 $ .55 share .................. ============ ============ Quarter Ended March 31, 2000 - ---------------------------- Our total earnings for the quarter ended March 31, 2000 decreased $10.7 million, or $ .07 per share, compared to the same period of 1999. Our total earnings decreased because we had lower earnings from our utility business before nonrecurring charges and we recorded a $4.2 million, or $2.5 million after-tax, expense for employees that elected to participate in a Targeted Voluntary Special Early Retirement Program (TVSERP) through March 31, 2000. This decrease was partially offset by higher earnings from our nonregulated businesses. In the first quarter of 2000, utility earnings before nonrecurring charges decreased compared to the same period of 1999 mostly due to the $37.5 million, or $22.7 million after-tax, amortization of the regulatory asset recorded for the reduction of BGE's generation plant as provided for under the Restructuring Order. This was 19 partially offset by higher electric sales and lower operations and maintenance expenses. We discuss our utility earnings, the Restructuring Order, and the TVSERP in more detail in the Utility Business section below. In the first quarter of 2000, nonregulated earnings increased compared to the same period of 1999 mostly because of higher power marketing earnings from our domestic wholesale energy business. We discuss our nonregulated earnings in more detail in the Nonregulated Businesses section beginning on page 25. Utility Business - ---------------- Before we go into the details of our electric and gas operations, we believe it is important to discuss factors that have a strong influence on our utility business performance: electric restructuring, regulation by the Maryland PSC, the weather, and other factors, including the condition of the economy in our service territory. Electric Restructuring - ---------------------- On April 8, 1999, Maryland enacted the Electric Customer Choice and Competition Act of 1999 (the "Act") and accompanying tax legislation that will significantly restructure Maryland's electric utility industry and modify 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 1999 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 below. o All customers, except a few commercial and industrial companies that have signed contracts with BGE, will be able to choose their electric energy supplier beginning July 1, 2000. BGE will provide a standard offer service for customers that do not select an alternative supplier. In either case, BGE will continue to deliver electricity to all customers in areas traditionally served by BGE. o BGE's current electric base rates are frozen at their current levels until July 1, 2000. o BGE will reduce residential base rates by approximately 6.5%, on average about $54 million a year, beginning July 1, 2000. These rates will not change before July 2006. o Commercial and industrial customers will have up to four service options that will fix electric energy rates and transition charges for a period that generally ranges from four to six years. o BGE's electric fuel rate clause will be discontinued effective July 1, 2000. o Electric delivery service rates will be frozen for a four-year period for commercial and industrial customers. The generation and transmission components of rates will be frozen for different time periods depending on the service options selected by those customers. o BGE will be allowed to recover $528 million after-tax of its potentially stranded investments and utility restructuring costs through a competitive transition charge on customers' bills. Residential customers will pay this charge for six years. Commercial and industrial customers will pay in a lump sum or over the four to six-year period, depending on the service option selected by each customer. o Generation-related regulatory assets and nuclear decommissioning costs will be included in delivery service rates effective July 1, 2000 and will be recovered on a basis approximating their existing amortization schedules. o Starting July 1, 2000, BGE will unbundle rates to show separate components for delivery service, transition charges, standard offer services (generation), transmission, universal service, and taxes. o No earlier than July 1, 2000, and upon receipt of all regulatory approvals, BGE will transfer, at book value, its ten Maryland-based fossil and nuclear power plants and its partial ownership interest in two coal plants and a hydroelectric plant in Pennsylvania to nonregulated subsidiaries of Constellation Energy. o BGE will reduce its generation assets, as discussed in Note 4 of our 1999 Annual Report on Form 10-K, by $150 million pre-tax during the period July 1, 1999 - June 30, 2000 to mitigate a portion of BGE's potentially stranded investments. o Universal service will be provided for low-income customers without increasing their bills. BGE will provide its share of a statewide fund totaling $34 million annually. 20 We believe that the Restructuring Order provided sufficient details of the transition plan to competition for BGE's electric generation business to require BGE to discontinue the application of Statement of Financial Accounting Standards (SFAS) No. 71, Accounting for the Effects of Certain Types of Regulation for that portion of its business. Accordingly, in the fourth quarter of 1999, we adopted the provisions of SFAS No. 101, Regulated Enterprises - Accounting for the Discontinuation of FASB Statement No. 71 and Emerging Issues Task Force Consensus (EITF) No. 97-4, Deregulation of the Pricing of Electricity - - Issues Related to the Application of FASB Statements No. 71 and 101 for BGE's electric generation business. BGE's transmission and distribution business continues to meet the requirements of SFAS No. 71 as that business remains regulated. We describe the effect of applying these accounting requirements in Note 4 of our 1999 Annual Report on Form 10-K. 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. MAPSA also filed a motion to delay the implementation of the Restructuring Order pending a decision on the merits of the appeals by the court. In April 2000, the court dismissed the appeal and motion filed by MAPSA. We believe that the remaining appeals are without merit. However, no assurances can be given as to the timing or outcome of these cases, and whether the outcome will have a material adverse effect on our, and BGE's, financial results. Regulation by the Maryland PSC - ------------------------------ Under traditional rate regulation that will continue for all of BGE's businesses except electric generation beginning July 1, 2000, the Maryland PSC determines the rates we can charge our customers. Currently, our rates consist of a "base rate," a "conservation surcharge," and a "fuel rate." Base Rate - --------- The base rate is the rate the Maryland PSC allows us to charge our customers for the cost of providing them service, plus a profit. We have 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. Except as provided under the terms of the electric Restructuring Order discussed earlier, 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. We discuss this filing in the gas Base Rates section on page 24. Conservation Surcharge - ---------------------- The Maryland PSC allows us to include in electric and gas rates a component to recover money spent on conservation programs. This component is called a "conservation surcharge." However, under this surcharge the Maryland PSC limits what our profit can be. If, at the end of the year we have exceeded our allowed profit, we defer (include as a liability in our Consolidated Balance Sheets and exclude from our Consolidated Statements of Income) the excess in that year and we lower the amount of future surcharges to our customers to correct the amount of overage, plus interest. As a result of the Restructuring Order, the electric conservation surcharge was frozen at its current level and the associated profit limitation is no longer applicable. Fuel Rate - --------- Currently, we charge our electric customers separately for the fuel we use to generate electricity (nuclear fuel, coal, gas, or oil) and for the net cost of purchases and sales of electricity. We charge the actual cost of these items to the customer with no profit to us. If these fuel costs go up, the Maryland PSC permits us to increase the fuel rate. If these costs go down, our customers benefit from a reduction in the fuel rate. The fuel rate is mostly impacted by the amount of electricity generated at Calvert Cliffs because the cost of nuclear fuel is cheaper than coal, gas, or oil. Under the Restructuring Order, BGE's electric fuel rate is frozen at its current level until July 1, 2000, at which time the fuel rate clause will be discontinued. We will continue to defer the difference between our actual costs of fuel and energy and what we collected from customers under the fuel rate through June 30, 2000. After that date, earnings will be affected by the changes in the cost of fuel and energy. We discuss our exposure to market risk further in the Current Issues section on page 17. In addition, any accumulated difference between our actual costs of fuel and energy and the amounts collected from customers under the electric fuel rate clause will be collected from our customers over a period to be determined by the Maryland PSC. At March 31, 2000, the amount to be collected from customers was $60.3 million. 21 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 24 and in Note 1 of our 1999 Annual Report on Form 10-K. Weather - ------- Weather affects the demand for electricity and gas. Very hot summers and very cold winters increase demand. Mild weather reduces demand. Weather impacts residential sales more than commercial and industrial sales, which are mostly affected by business needs for electricity and gas. 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. The Maryland PSC allows us to record a monthly adjustment to our gas business revenues to eliminate the effect of abnormal weather patterns. We discuss this further in the Weather Normalization section on page 24. We show the number of heating degree days in the quarter ended March 31, 2000 and 1999, and the percentage change in the number of degree days between these periods in the following table: Quarter Ended March 31 ---------------------- 2000 1999 ----------- --------- Heating degree days............ 2,305 2,389 Percent change from prior period (3.5%) Other Factors - ------------- Other factors, aside from weather, impact the demand for electricity and gas. These factors include the "number of customers" and "usage per customer" during a given period. We use these terms later in our discussions of 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. When customer choice for electric generation begins on July 1, 2000, a portion of BGE's electric customers will become delivery service customers only and will purchase their electricity from other sources. 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. Utility Earnings Per Share of Common Stock - ------------ Quarter Ended March 31 ------------------------ 2000 1999 ------------ ---------- Regulated electric business $ .22 $ .31 Regulated gas business ... .14 .14 ------------ ----------- Total utility earnings per share before nonrecurring charge included in operations ............. .36 .45 Nonrecurring charge included in operations: TVSERP .................. (.02) - ------------ ----------- Total utility earnings per share ............. $ .34 $ .45 ============ =========== Our utility earnings for the quarter ended March 31, 2000 decreased $16.9 million, or $.11 per share compared to the same period of 1999. We discuss the factors affecting utility earnings on page 23. 22 Regulated Electric Business - --------------------------- The discussion below reflects the operations of the electric generation portion of our utility business under current rate regulation by the Maryland PSC. Our electric business will change significantly beginning July 1, 2000 as we enter into retail customer choice for electric generation as discussed earlier in the Introduction and Current Issues sections. Electric Revenues - ----------------- The changes in electric revenues in 2000 compared to 1999 were caused by: Quarter Ended March 31 2000 vs. 1999 ------------- (In millions) Electric system sales volumes ..... $ 8.3 Base rates ........................ 0.2 Fuel rates ........................ 3.2 ------------ Total change in electric revenues from electric system sales ...... 11.7 Interchange and other sales ....... (1.2) Other ............................. 0.9 ------------ Total change in electric revenues . $ 11.4 ============ 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 2000 compared to 1999 were: Quarter Ended March 31 2000 vs. 1999 -------------- Residential........................ 3.1% Commercial......................... 3.6 Industrial......................... (1.9) During the quarter ended March 31, 2000, we sold more electricity to residential customers due to higher usage per customer. We sold more electricity to commercial customers due to higher usage per customer and an increased number of customers. We sold less electricity to industrial customers mostly because usage by industrial customers decreased. Base Rates - ---------- During the quarter ended March 31, 2000, base rate revenues were about the same compared to the same period of 1999. Fuel Rates - ---------- During the quarter ended March 31, 2000, fuel rate revenues increased compared to the same period mostly because we sold more electricity. Interchange and Other Sales - --------------------------- "Interchange and other sales" are sales in the PJM (Pennsylvania-New Jersey-Maryland) Interconnection energy market and to others. The 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. We sell energy to PJM members and to others after we have satisfied the demand for electricity in our own system. During the quarter ended March 31, 2000, we had lower interchange and other sales compared to the same period of 1999 mostly because the increased demand for system sales reduced the amount of energy we had available for off-system sales. Electric Fuel and Purchased Energy Expenses - ------------------------------------------- Quarter Ended March 31 2000 1999 ----------- --------- (In millions) Actual costs................ $ 121.8 $ 127.2 Net deferral of costs under electric fuel rate clause (3.2) (6.1) ----------- ---------- Total electric fuel and purchased energy expenses................ $ 118.6 $ 121.1 =========== ========== Actual Costs - ------------ During the quarter ended March 31, 2000, our actual costs of fuel to generate electricity (nuclear fuel, coal, gas, or oil) and electricity we bought from others was lower compared to the same period of 1999 mostly because of lower purchased energy costs. Electric Fuel Rate Clause - ------------------------- Under the electric fuel rate clause, we defer (include as an asset or liability on the Consolidated Balance Sheets and exclude from the Consolidated Statements of Income) the difference between our actual costs of fuel and energy and what we collect from customers under the fuel rate in a given period. We either bill or refund our customers that difference in the future. We discuss the calculation of the fuel rate and its future discontinuance in Note 1 of our 1999 Annual Report on Form 10-K. During the quarter ended March 31, 2000, our actual costs of fuel and energy were higher than the fuel rate revenues we collected from our customers. 23 Electric Operations and Maintenance Expenses - -------------------------------------------- During the quarter ended March 31, 2000, electric operations and maintenance expenses decreased $5.2 million compared to 1999 mostly because of the timing of costs for the annual refueling outage at Calvert Cliffs and costs related to a major winter ice storm during 1999 that had a negative impact on earnings in that year. This decrease was partially offset by a $4.2 million expense for electric business employees that elected to participate in a Targeted Voluntary Special Early Retirement Program (TVSERP) through March 31, 2000. We estimate that we will record an additional $5 million of expense in the second quarter 2000 for any other electric business employees that elected to participate by the April 14, 2000 closing of the acceptance period for this program. Electric Depreciation and Amortization Expense - ---------------------------------------------- During the quarter ended March 31, 2000, electric depreciation and amortization expense increased $39.6 million compared to 1999 mostly because of the $37.5 million amortization of the regulatory asset for the reduction in generation plant provided for in the Restructuring Order. Regulated Gas Business - ---------------------- 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 2000 compared to 1999 were caused by: Quarter Ended March 31 2000 vs. 1999 ------------ (In millions) Gas system sales volumes .......... $ 4.0 Base rates ........................ (0.5) Weather normalization ............. (2.8) Gas cost adjustments .............. (13.4) ------------ Total change in gas revenues from gas system sales ............... (12.7) Off-system sales .................. 14.1 Other ............................. 0.3 ------------ Total change in gas revenues ...... $ 1.7 ============ Gas System Sales Volumes - ------------------------ The percentage changes in our gas system sales volumes, by type of customer, in 2000 compared to 1999 were: Quarter Ended March 31 2000 vs. 1999 ---------------------- Residential........................ 0.9% Commercial......................... 4.2 Industrial......................... (2.3) During the quarter ended March 31, 2000, we sold about the same amount of gas to residential customers as we did during the same period of 1999. We sold more gas to commercial customers due to higher usage per customer and an increased number of customers. This was partially offset by milder winter weather. We sold less gas to industrial customers mostly because of milder winter weather, fewer customers, and decreased usage by Bethlehem Steel. Base Rates - ---------- During the quarter ended March 31, 2000, base rate revenues were about the same compared to the same period of 1999. On November 17, 1999, we applied for a $36.3 million annual increase in our gas base rates. In May 2000, we received a proposed order from the Hearing Examiner for a $7.7 million annual increase. Currently, we are reviewing the proposed order and expect to appeal certain aspects of the order to the Maryland PSC. At the date of this report, we cannot estimate the amount of the final order, but we expect it will be significantly less than the amount requested. We expect the Maryland PSC to issue a final order in June 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. These clauses operate similarly to the electric fuel rate clause described in the Electric Fuel Rate Clause section on page 23. 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, and does not significantly impact earnings. 24 Delivery service customers, including Bethlehem Steel, are not subject to the gas cost adjustment clauses because we are not selling gas to them. We charge these customers fees to recover the fixed costs for the transportation service we provide. These fees are the same as the base rate charged for gas sales and are included in gas system sales volumes. During the quarter ended March 31, 2000, gas cost adjustment revenues decreased compared to the same period of 1999 mostly because we sold less gas to customers. 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 March 31, 2000, revenues from off-system gas sales increased compared to the same period of 1999 mostly because we sold more gas off-system at a higher price. Gas Purchased For Resale Expenses - --------------------------------- Quarter Ended March 31 2000 1999 --------- -------- (In millions) Actual costs.................... $106.1 $ 93.2 Net (deferral) recovery of costs under gas adjustment clauses.. (3.2) 8.9 ------------------ Total gas purchased for resale expenses............. $102.9 $102.1 ================== Actual Costs - ------------ 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 March 31, 2000, actual gas costs increased compared to the same period of 1999 mostly because we bought more gas for off-system sales. Gas Adjustment Clauses - ---------------------- We charge customers for the cost of gas sold through gas adjustment clauses (determined by the Maryland PSC), as discussed under Gas Cost Adjustments earlier in this section. During the quarter ended March 31, 2000, our actual gas costs were higher than the fuel rate revenues we collected from our customers. Gas Operations and Maintenance Expenses - --------------------------------------- During the quarter ended March 31, 2000, gas operations and maintenance expenses decreased slightly compared to 1999. Gas Depreciation and Amortization Expense - ----------------------------------------- During the quarter ended March 31, 2000, gas depreciation and amortization expense was about the same compared to 1999. Nonregulated Businesses - ----------------------- Our nonregulated businesses engage primarily in domestic wholesale energy services as discussed in the Introduction section on page 16. We describe our nonregulated businesses in more detail in our 1999 Annual Report on Form 10-K in Item 1. Business -- Diversified Businesses. Nonregulated Earnings Per Share of Common Stock - ----------------------------------------------- Quarter Ended March 31 2000 1999 -------- -------- Domestic wholesale energy Power marketing............. $ .09 $ .05 Domestic power projects..... .04 .04 -------- -------- Total domestic wholesale energy earnings per share.......... .13 .09 Other nonregulated businesses earnings per share.......... .01 .01 --------- -------- Total nonregulated earnings per share.................. $ .14 $ .10 ======= ======= Our total nonregulated earnings for the quarter ended March 31, 2000 increased $6.2 million, or $.04 per share, compared to the same period of 1999. We discuss the factors affecting the earnings of our nonregulated businesses below. Domestic Wholesale Energy - ------------------------- Power Marketing - --------------- During the quarter ended March 31, 2000, earnings from our power marketing business increased compared to the same period of 1999 mostly because of increased transaction volumes, partially offset by lower margins and increased operating expenses associated with the growth of the business. 25 Constellation Power Source uses the mark-to-market method of accounting. We discuss the mark-to-market method of accounting and Constellation Power Source's activities in more detail in Note 1 of our 1999 Annual Report on Form 10-K. As a result of the nature of its business activities, Constellation Power Source's revenue 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. Assets and liabilities from energy trading activities (as shown in our Consolidated Balance Sheets beginning on page 4) increased at March 31, 2000 compared to December 31, 1999 because of business growth during the period. Domestic Power Projects - ----------------------- During the quarter ended March 31, 2000, earnings from our domestic power projects business were about the same compared to the same period of 1999. California Power Purchase Agreements - ------------------------------------ Constellation Power and subsidiaries and Constellation Investments have $295.8 million invested in 14 projects that sell electricity in California under power purchase agreements called "Interim Standard Offer No. 4" agreements. During the quarter ended March 31, 2000, earnings from these projects were $6.9 million, or $.05 per share, compared to $8.0 million, or $.05 per share for the same period of 1999. Under these agreements, the electricity rates change from fixed rates to variable rates beginning in 1996 and continuing through 2000. The projects which already have had rate changes have lower revenues under variable rates than they did under fixed rates. When the remaining projects transition to variable rates, we expect their revenues also to be lower than they are under fixed rates. At the date of this report, 11 projects had already transitioned to variable rates. The remaining three projects will transition in November and December 2000. The project that changed over during the quarter ended March 31, 2000 contributed $2.7 million, or $.02 per share to the earnings. Those changing over later in 2000 contributed $5.1 million, or $.03 per share to the earnings. Our power projects business continues to pursue alternatives for some of these projects including: o repowering the projects to reduce operating costs, o changing fuels to reduce operating costs, o renegotiating the power purchase agreements to improve the terms, o restructuring financing to improve existing terms, and o selling its ownership interests in the projects. We evaluate the carrying amount of our investment in these projects for impairment using the methodology discussed in Note 1 of our 1999 Annual Report of Form 10-K. Constellation Power's management uses its best estimates to determine if there has been an impairment of these investments and considers various factors including forward price curves for energy, fuel costs, and operating costs. However, it is possible that future estimates of market prices and project costs could vary from those used in evaluating these assets, and the impact of such variations could be material. We also describe these projects and the transition process in the Notes to Consolidated Financial Statements on page 15. In April 2000, Constellation Operating Services, Inc. (COSI), a subsidiary of Constellation Power, Inc., ended its exclusive arrangement with Orion Power Holdings, Inc. to operate Orion's facilities. Orion purchased from COSI the four subsidiary companies formed to operate power plants owned by Orion. Other Nonregulated Businesses - ----------------------------- During the quarter ended March 31, 2000, earnings from our other nonregulated businesses were about the same compared to the same period of 1999. Earnings from our financial investments business were higher compared to the same period of 1999 mostly because of better market performance for its investments. This was primarily offset by lower earnings in our real estate and senior-living facilities business. 26 In December 1999, we decided to exit the international portion of our power projects business as part of our strategy to improve our competitive position. We expect to complete our exit strategy by the end of 2000. We discuss our strategy further in the Strategy section on page 17. 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 business 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, and the strength of the economy in general when making decisions about our real estate and senior-living projects. If we were to decide to sell our projects, we could have write-downs. In addition, if we were to sell our projects in the current market, we would have losses which could be material, although the amount of the losses is hard to predict. Depending on market conditions, we could also have material losses on any future sales. Our current real estate and senior-living strategy is to hold each project until we can realize a reasonable value for it. Under accounting rules, we are required to write down the value of a project to market value in either of two cases. The first is if we change our intent about a project from an intent to hold to an intent to sell and the market value of that project is below book value. The second is if the expected cash flow from the project is less than the investment in the project. Consolidated Nonoperating Income and Expenses - --------------------------------------------- Fixed Charges - ------------- During the quarter ended March 31, 2000, fixed charges were about the same compared to the same period of 1999. Income Taxes - ------------ During the quarter ended March 31, 2000, our total income taxes increased $2.1 million compared to the same period of 1999 mostly because we had higher taxable income from our nonregulated businesses and a $10.3 million increase at BGE as a result of comprehensive changes to the state and local tax laws. This was partially offset by lower taxable income from BGE. We discuss the comprehensive tax law changes in Note 4 of our 1999 Annual Report on Form 10-K. Financial Condition - ------------------- Cash Flows - ---------- Quarter Ended March 31 -------------------- 2000 1999 ---------- --------- (In millions) Cash provided by (used in): Operating Activities $ 298.0 $ 317.5 Investing Activities (128.0) (67.6) Financing Activities (194.5) (79.6) During the quarter ended March 31, 2000, we generated less cash from operations compared to the same period in 1999 mostly because of changes in working capital requirements. During the quarter ended March 31, 2000, we used more cash for investing activities compared to the same period in 1999 mostly due to an increase in investment in our domestic power projects business and an increase in utility construction expenditures. In addition, our real estate and senior-living facilities business received less cash compared to the same period of 1999, due to the sale of a project in 1999. We did not have a similar sale in 2000. During the quarter ended March 31, 2000, we used more cash for financing activities compared to the same period of 1999 mostly because our net short-term borrowings and long-term debt decreased compared to the same period of 1999. 27 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 Duff & Phelps' & Poors Investors Credit Rating Group Service Rating Co. ------------ ---------- ------------- Constellation Energy - -------------------- Unsecured Debt A- A3 A BGE - --- Mortgage Bonds AA- A1 AA- Unsecured Debt A A2 A+ Trust Originated Preferred Securities and Preference Stock A- "a2" A Capital Resources - ----------------- Our business requires a great deal of capital. Our estimated annual amounts for the years 2000 through 2002, are shown in the table on page 29. For the twelve months ended March 31, 2000, the ratio of earnings to fixed charges for Constellation Energy was 2.82. The ratio of earnings to fixed charges for BGE was 3.40 and the ratio of earnings to combined fixed charges and preferred and preference dividend requirements for BGE was 3.07. 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 2000 through 2002 include estimates of funding for existing and anticipated projects. We continuously review and modify those estimates. Actual requirements may vary from the estimates included in the table on page 29 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 33. No earlier than July 1, 2000, and upon receipt of all regulatory approvals, all of BGE's generation assets will be transferred to nonregulated subsidiaries of Constellation Energy. The discussion and table for capital requirements on page 29 include these generation assets as part of the utility's regulated electric business through June 30, 2000. After that date, the capital requirements are included in the domestic wholesale energy business. 28
Calendar Year Estimates 2000 2001 2002 ----------- ---------- --------- (In millions) Utility Capital Requirements: - ----------------------------- Construction expenditures (excluding AFC): Regulated Electric: Generation (including nuclear fuel) $65 $ - $- Transmission and distribution 177 167 167 --------- -------- -------- Total regulated electric 242 167 167 Regulated Gas 56 54 54 Common 21 19 19 --------- -------- -------- Total construction expenditures 319 240 240 Retirement of long-term debt and redemption of preference stock 402 282 154 --------- -------- -------- Total utility capital requirements 721 522 394 --------- -------- -------- Nonregulated Capital Requirements: - ---------------------------------- Investment requirements: Domestic Wholesale Energy 765 * 991 747 Other 62 20 20 --------- -------- -------- Total investment requirements 827 1,011 767 Retirement of long-term debt 284 367 2 --------- -------- -------- Total nonregulated capital requirements 1,111 1,378 769 --------- -------- -------- Total capital requirements $ 1,832 $ 1,900 $ 1,163 ========= ======== ========
* Effective July 1, 2000, includes approximately $140 million for electric generation and nuclear fuel formerly part of BGE's regulated electric business. Capital Requirements - -------------------- Electric Generation - ------------------- Electric construction expenditures for our regulated electric segment include improvements to generating plants and costs for replacing the steam generators at Calvert Cliffs through June 30, 2000. Thereafter, these expenditures are reflected in our domestic wholesale energy segment. In March 2000, we received the license extension from the NRC that extends our operating licenses to 2034 for Unit 1 and 2036 for Unit 2 as discussed in the Current Issues section on page 17. If we do not replace the steam generators, we will not be able to operate the Calvert Cliffs units through our operating licenses period. 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 $ 40 million in 2000, o $ 64 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) and State of Maryland nitrogen oxides emissions (NOx) reduction regulations as follows: o $ 63 million in 2000, o $ 52 million in 2001, and o $ 4 million in 2002. We discuss the NOx regulations and timing of expenditures in the Environmental Matters section of the Notes to Consolidated Financial Statements on page 13. Electric Transmission and Distribution, and Gas - ----------------------------------------------- Electric transmission and distribution, and gas construction expenditures primarily include new business construction needs and improvements to existing facilities. 29 Domestic Wholesale Energy Business - ---------------------------------- Our domestic wholesale energy business will require additional funding for growing its power marketing business and developing and acquiring power projects. Our domestic wholesale energy business investment requirements include the planned construction of 800 megawatts of peaking capacity in the Mid-Atlantic/Mid-West region by the summer of 2001 and an additional 4,300 megawatts of peaking and combined cycle production facilities scheduled for completion in 2002 and beyond. Our investment requirements also include our domestic wholesale energy business commitment to contribute up to an additional $19.5 million in equity to Orion. To date, our domestic wholesale energy business has funded $205.5 million in equity to Orion. Funding for Capital Requirements - -------------------------------- BGE - --- Our utility business has met its capital requirements in the past primarily through internally generated funds. When BGE could not meet utility capital requirements internally, BGE sold debt and preference stock. BGE also sells securities when market conditions permit it to refinance existing debt or preference stock at a lower cost. The amount of cash BGE needs and market conditions determine when and how much BGE sells. Future funding for capital expenditures is expected from internally generated funds, commercial paper issuances, available capacity under credit facilities, and/or the issuance of long-term debt, trust securities, or preference stock. At March 31, 2000, FERC authorized BGE to issue up to $700 million of short-term borrowings, including commercial paper. In addition, BGE maintains $123 million in annual committed bank lines of credit and has $35 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. Domestic Wholesale Energy Business - ---------------------------------- Our domestic wholesale energy business has met its capital requirements in the past through borrowing, cash from its operations, and from time to time equity contributions from BGE or Constellation Energy. Future funding for the expansion of our domestic wholesale energy business is expected from internally generated funds, commercial paper issuances and long-term debt financing by Constellation Energy, and from time to time equity contributions from Constellation Energy. At March 31, 2000, Constellation Energy has a commercial paper program where it can issue up to $500 million in short-term notes to fund its nonregulated businesses. To support its commercial paper program, Constellation Energy maintains $35 million in annual and $15 million in multi-year committed bank lines of credit and has a $135 million revolving credit agreement, under which it can also issue letters of credit. In addition, Constellation Energy has access to interim lines of credit as required from time to time to support its outstanding commercial paper. 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, 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 business and market conditions in the Other Nonregulated Businesses section on page 26. 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 1999 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 Issued - --------------------------- In July 1999, the FASB issued SFAS No. 137 that delays the effective date for SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, by one year. Therefore, we must adopt the provisions of SFAS No. 133 in our financial statements for the quarter ended March 31, 2001. We are evaluating the implications of SFAS No. 133, but have not determined the effects on our financial results. However, SFAS No. 133 will not significantly impact our power marketing business as this business uses mark-to-market accounting. 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 section of Management's Discussion and Analysis on page 17, o quarterly financing activities in the Notes to Consolidated Financial Statements on page 12, and o activities of our power marketing business in the Power Marketing section of Management's Discussion and Analysis on page 25. 31 PART II. OTHER INFORMATION - --------------------------- Item 1. Legal Proceedings - ------------------------- 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 530 individuals that were never employees of BGE each claim $6 million in damages ($2 million compensatory and $4 million punitive). These claims were filed in the Circuit Court for Baltimore City, Maryland in the summer of 1993. We do not know the specific facts necessary to estimate our potential liability for these claims. The specific facts we do not know include: o the identity of our facilities at which the plaintiffs allegedly worked as contractors, o the names of the plaintiff's employers, and o the date on which the exposure allegedly occurred. To date, 25 of these cases were settled for amounts that were not significant. The second type is claims by one manufacturer -- Pittsburgh Corning Corp. -- against us and approximately eight others, as third-party defendants. 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 260 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 - ------------------- Three separate appeals of the Restructuring Order issued by the Maryland PSC have been filed. Two appeals, one by Trigen - Baltimore Energy Corporation and the other by Sweetheart Cup Company were filed on December 9, 1999 in the Circuit Court for Baltimore City. The third appeal was filed by the Mid-Atlantic Power Supply Association (MAPSA) on December 10, 1999 in the Circuit Court for Prince George's County. MAPSA's appeal was transferred to the Circuit Court for Baltimore City. Each appeal asks for a review of the Restructuring Order. MAPSA also filed a motion to delay the implementation of the Restructuring Order pending a decision on the merits of the appeals by the court. In April 2000, the court dismissed the appeal and motion filed by MAPSA. We believe that the remaining appeals are without merit. However, no assurances can be given as to the timing or outcome of these cases, and whether the outcome will have a material adverse effect on our, and BGE's, financial results. These appeals are described further in the Electric Restructuring section of Management's Discussion and Analysis on page 20. Other - ----- Please refer to page 24 for discussion of our appeal of certain aspects regarding our gas base rate filing with the Maryland PSC. In addition, please refer to page 19 for discussion of FERC Order 2000 regarding regional transmission organizations. We are appealing certain aspects of that Order. Finally, please refer to page 19 for a discussion of the National Whistleblowers Center's appeal of a NRC decision concerning the relicensing of Calvert Cliffs. 32 PART II.OTHER INFORMATION (Continued) - ------------------------------------ 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 general economic, business, and regulatory conditions, o energy supply and demand, o competition, 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, o commodity price risk, o operating our currently regulated generation assets in a deregulated market beginning July 1, 2000 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, and o implications from the transfer of BGE's generation assets to nonregulated subsidiaries of Constellation Energy. 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. Exhibit No. 27(a) Constellation Energy Group, Inc. Financial Data Schedule. Exhibit No. 27(b) Baltimore Gas and Electric Company Financial Data Schedule. Exhibit No. 99 BGE Pro Forma Financial Statements - Generation Asset Transfer. (b)Reports on Form 8-K for the quarter ended March 31, 2000: Date Filed Items Reported ---------- -------------- February 15, 2000 Item 5. Other Events Item 7. Exhibits March 17, 2000 Item 5. Other Events Item 7. Exhibits 33 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: May 15, 2000 /s/ D. A. Brune ------------ ------------------------------------------------ D. A. Brune, Vice President on behalf of each Registrant and as Principal Financial Officer of each Registrant EX-12 2 EXHIBIT 12 (A) CONSTELLATION ENERGY GROUP, INC. AND SUBSIDIARIES COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES
12 Months Ended -------------------------------------------------------------------------------------- March December December December December December 2000 1999 1998 1997 1996 1995 ----------- ----------- ----------- ----------- ----------- ----------- (In Millions of Dollars) Income from Continuing Operations (Before Extraordinary Loss) $ 315.7 $ 326.4 $ 305.9 $ 254.1 $ 272.3 $ 297.4 Taxes on Income, Including Tax Effect for BGE Preference Stock Dividends 184.4 182.5 169.3 145.1 148.3 152.0 ----------- ----------- ----------- ----------- ----------- ----------- Adjusted Income $ 500.1 $ 508.9 $ 475.2 $ 399.2 $ 420.6 $ 449.4 ----------- ----------- ----------- ----------- ----------- ----------- Fixed Charges: Interest and Amortization of Debt Discount and Expense and Premium on all Indebtedness $ 245.2 $ 245.7 $ 255.3 $ 234.2 $ 203.9 $ 206.7 Earnings required for BGE Preference Stock Dividends 21.0 21.0 33.8 45.1 59.4 61.0 Capitalized Interest 3.9 2.7 3.6 8.4 15.7 15.0 Interest Factor in Rentals 2.2 1.8 1.9 1.9 1.5 2.1 ----------- ----------- ----------- ----------- ----------- ----------- Total Fixed Charges $ 272.3 $ 271.2 $ 294.6 $ 289.6 $ 280.5 $ 284.8 ----------- ----------- ----------- ----------- ----------- ----------- Earnings (1) $ 768.5 $ 777.4 $ 766.2 $ 680.4 $ 685.4 $ 719.2 =========== =========== =========== =========== =========== =========== Ratio of Earnings to Fixed Charges 2.82 2.87 2.60 2.35 2.44 2.52
(1) Earnings are deemed to consist of income from continuing operations (before extraordinary loss) that includes earnings of Constellation Energy's consolidated subsidiaries, equity in the net income of BGE's unconsolidated subsidiary, 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 3 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 -------------------------------------------------------------------------------------- March December December December December December 2000 1999 1998 1997 1996 1995 ----------- ---------- ----------- ----------- ----------- ----------- (In Millions of Dollars) Income from Continuing Operations (Before Extraordinary Loss) $ 296.3 $ 328.4 $ 327.7 $ 282.8 $ 310.8 $ 338.0 Taxes on Income 167.5 182.0 181.3 161.5 169.2 172.4 ----------- ---------- ----------- ----------- ----------- ----------- Adjusted Income $ 463.8 $ 510.4 $ 509.0 $ 444.3 $ 480.0 $ 510.4 ----------- ---------- ----------- ----------- ----------- ----------- Fixed Charges: Interest and Amortization of Debt Discount and Expense and Premium on all Indebtedness $ 192.3 $ 206.4 $ 255.3 $ 234.2 $ 203.9 $ 206.7 Capitalized Interest 0.1 0.4 3.6 8.4 15.7 15.0 Interest Factor in Rentals 0.9 1.0 1.9 1.9 1.5 2.1 ----------- ---------- ----------- ----------- ----------- ----------- Total Fixed Charges $ 193.3 $ 207.8 $ 260.8 $ 244.5 $ 221.1 $ 223.8 ----------- ---------- ----------- ----------- ----------- ----------- Preferred and Preference Dividend Requirements: (1) Preferred and Preference Dividends $ 13.4 $ 13.5 $ 21.8 $ 28.7 $ 38.5 $ 40.6 Income Tax Required 7.6 7.5 12.0 16.4 20.9 20.4 ----------- ---------- ----------- ----------- ----------- ----------- Total Preferred and Preference Dividend Requirements $ 21.0 $ 21.0 $ 33.8 $ 45.1 $ 59.4 $ 61.0 ----------- ---------- ----------- ----------- ----------- ----------- Total Fixed Charges and Preferred and Preference Dividend Requirements $ 214.3 $ 228.8 $ 294.6 $ 289.6 $ 280.5 $ 284.8 =========== ========== =========== =========== =========== =========== Earnings (2) $ 657.0 $ 717.8 $ 766.2 $ 680.4 $ 685.4 $ 719.2 =========== ========== =========== =========== =========== =========== Ratio of Earnings to Fixed Charges 3.40 3.45 2.94 2.78 3.10 3.21 Ratio of Earnings to Combined Fixed Charges and Preferred and Preference Dividend Requirements 3.07 3.14 2.60 2.35 2.44 2.52
(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, equity in the net income of BGE's unconsolidated subsidiary, income taxes (including defered income taxes and investment tax credit adjustments), and fixed charges other than capitalized interest. EX-27 4 FINANCIAL DATA SCHEDULE
UT THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM CONSTELLATION ENERGY'S MARCH 31, 2000 INTERIM CONSOLIDATED INCOME STATEMENT, BALANCE SHEET AND STATEMENT OF CASH FLOWS AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH STATEMENTS. 0001004440 Constellation Energy Group 1,000,000 3-MOS DEC-31-2000 JAN-01-2000 MAR-31-2000 PER-BOOK 5,511 2,045 1,422 650 0 9,628 1,497 0 1,508 3,018 0 190 2,488 0 0 340 798 0 0 0 2,794 9,628 992 52 809 861 131 5 136 64 72 0 72 63 59 298 0.48 0.48
EX-27 5 FINANCIAL DATA SCHEDULE
UT THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM BALTIMORE GAS AND ELECTRIC COMPANY'S MARCH 31, 2000 INTERIM CONSOLIDATED INCOME STATEMENT, BALANCE SHEET AND STATEMENT OF CASH FLOWS AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH STATEMENTS. 0000009466 Baltimore Gas and Electric Company 1,000,000 3-MOS DEC-31-2000 JAN-01-2000 MAR-31-2000 PER-BOOK 5,511 419 564 640 0 7,134 1,495 0 850 2,345 0 190 2,119 0 0 88 544 0 0 0 1,848 7,134 721 36 587 623 98 3 101 47 54 3 51 63 44 256 0 0
EX-99 6 PRO FORMA FINANCIAL STATEMENTS EXHIBIT 99 BGE PRO FORMA FINANCIAL STATEMENTS - GENERATION ASSET TRANSFER BACKGROUND As previously reported in our March 17, 2000 Report on Form 8-K (incorporated by reference in our 1999 Annual Report on Form 10-K), we presented 1999 pro forma financial statements for Baltimore Gas and Electric Company (BGE), a subsidiary of Constellation Energy Group, Inc. (Constellation Energy). As a result of the deregulation of BGE's electric generation, we expect BGE to transfer, at book value, certain generation assets and liabilities to Calvert Cliffs, Inc. (CCI) and Constellation Generation, Inc. (CGI), nonregulated subsidiaries of Constellation Energy, no earlier than July 1, 2000 and upon the receipt of all regulatory approvals. The pro forma financial statements and description of the pro forma adjustments reflect these transfers and other financial impacts surrounding the deregulation of BGE's electric generation business. We discuss the deregulation of BGE's electric generation business further in this Quarterly Report on Form 10-Q in the Electric Restructuring section of Management's Discussion and Analysis and in our 1999 Annual Report on Form 10-K. Since our 1999 Annual Report on Form 10-K, there have been new developments in the assumptions used in these pro forma financial statements. Accordingly, we are providing revised pro forma financial statements to reflect certain known changes in the assumptions. These changes primarily result from the Internal Revenue Service's (IRS) determination that the issuance of certain unsecured notes would not qualify as a tax-free transaction. Based on this determination, we have reduced the level of unsecured promissory notes that BGE expected to transfer to our nonregulated subsidiaries from $1.1 billion, as disclosed in our 1999 Annual Report on Form 10-K, to approximately $426 million. Also, we have updated our estimates of other amounts to be transferred based on more recent information. The transfer of BGE's generating assets to CCI and CGI continues to be subject to various conditions, including the receipt of satisfactory federal and state regulatory approvals. Nuclear Regulatory Commission approval of the transfer of the operating licenses of Calvert Cliffs Nuclear Power Plant Units 1 and 2 and of the decommissioning trusts will be necessary. We have filed for a ruling from the IRS that the transfer of the generation assets, including the nuclear decommissioning trusts, and the assignment of BGE tax exempt debt and the revised issuance of unsecured promissory notes by CCI and CGI, can occur on a tax free basis. Approvals from the Federal Energy Regulatory Commission, the Maryland PSC (PSC), and the Pennsylvania Public Utility Commission will also be required in conjunction with these transactions. There can be no assurance as to the receipt of these or any other regulatory approvals or the actual timing of the asset transfer. 1 DESCRIPTION OF PRO FORMA FINANCIAL INFORMATION The following consolidated financial statements for BGE are filed with this Exhibit: o Unaudited Condensed Pro Forma Balance Sheet At March 31, 2000, and o Unaudited Condensed Pro Forma Income Statement for the Year Ended December 31, 1999 (Revised) and for the Three Month Period Ended March 31, 2000. The following major assumptions were made in preparing these pro forma financial statements: o The transfers described above were assumed to occur as of March 31, 2000 for the purposes of the condensed pro forma balance sheet. o The transfers described above were assumed to occur as of January 1, 1999 for the purposes of the revised condensed pro forma income statement for the year ended December 31, 1999. The transfers were assumed to occur as of January 1, 2000 for the purposes of the condensed pro forma income statement for the three-month period ended March 31, 2000. However, 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. o The transfer of the generating assets and decommissioning trusts was assumed to occur at book value and on a non-taxable basis. o The provisions of the PSC's Restructuring Order are assumed to be effective as of the beginning of each period presented for the purposes of developing BGE's revenues and electric purchased fuel and energy expenses included in the condensed pro forma income statements. o An effective tax rate of approximately 35% was utilized to develop the income tax effects of adjustments to the revised condensed pro forma income statement for the year ended December 31, 1999. An effective tax rate of approximately 39.55% was utilized for the three-month period ended March 31, 2000. The difference in the effective tax rate results from the comprehensive changes in the state and local tax laws that began January 1, 2000. We discuss these comprehensive tax law changes in Note 4 of our 1999 Annual Report on Form 10-K. These pro forma financial statements have been prepared for comparative purposes only and do not purport to be indicative of the results of operations or financial condition which would have actually resulted if the transfer of the generation assets or other related transactions had been made on the dates or for the periods presented, or which may result in the future. Further, these pro forma financial statements have been prepared using information available at the date of this filing. As a result, certain amounts indicated herein are preliminary in nature and, therefore, are subject to change in the future. 2 DESCRIPTION OF PRO FORMA ADJUSTMENTS The Unaudited Condensed Pro Forma Income Statements and Balance Sheet filed with this Exhibit reflect the following adjustments: Income Statements Adjustments - ----------------------------- 1. The expected reduction of BGE's revenues to remove $112 million of interchange and other wholesale sales for the year ended December 31, 1999 ($23 million for the three-month period ended March 31, 2000), which will no longer be a part of its business once electric deregulation occurs. 2. The adjustment of BGE's revenues to reflect the $54 million average, annual residential rate reduction provided for in the Restructuring Order for the year ended December 31, 1999 ($13 million for the three-month period ended March 31, 2000). 3. The anticipated transfer to CCI of approximately $164 million of BGE's revenues that will fund nuclear decommissioning and stranded costs for the year ended December 31, 1999 ($40 million for the three-month period ended March 31, 2000). 4. The reversal of BGE's actual electric fuel and purchased energy costs of approximately $487 million for the year ended December 31, 1999 ($119 million for the three-month period ended March 31, 2000), and its replacement with the estimated $1,187 million cost of power BGE would have purchased from CPS to meet its system sales load for the year ended December 31, 1999 ($267 million for the three-month period ended March 31, 2000) at standard offer service rates provided for in the Restructuring Order. 5. The expected elimination of operation and maintenance expenses directly and indirectly relating to the generation function for the respective period. 6. The anticipated elimination of approximately $165 million of depreciation, amortization, and nuclear decommissioning expense relating to the transferred assets for the year ended December 31, 1999 ($42.5 million for the three-month period ended March 31, 2000). 7. The removal from results of the nonrecurring impact of $75 million of amortization expense relating to the $150 million reduction of electric generation plant that will occur prior to the actual generation asset transfer under the terms of the Restructuring Order for the year ended December 31, 1999 ($37.5 million for the three-month period ended March 31, 2000). 8. The estimated reduction to taxes other than income taxes resulting from the transfer of the generation function for the respective period. 9. The reduction to other income associated with the elimination of the equity portion of the allowance for funds used during construction relating to generation construction projects, equity in the earnings of Safe Harbor Water Power Corporation, and after-tax earnings on the nuclear decommissioning trusts. 10. The reflection in other income of approximately $26 million of interest income expected to be earned on the unsecured promissory notes described in this Exhibit for the year ended December 31, 1999 ($7 million for the three-month period ended March 31, 2000). 11. The reduction of fixed charges to approximate interest expense expected to be avoided on the transferred tax-exempt debt. 12. The estimated income tax effects using the effective income tax rates for the respective period. 13. The elimination of the amortization of deferred investment tax credits which are expected to be transferred along with the associated generation assets. 3 Balance Sheet Adjustments - ------------------------- 1. The expected transfer of fuel stocks including SO2 emission allowances, materials and supplies, and nuclear fuel inventories relating to the generation function. 2. The reflection of the current and non-current portions of, along with the approximate amount of accrued interest on, the unsecured promissory notes described in this Exhibit. 3. The expected transfer of nuclear decommissioning to CCI. 4. The expected transfer of BGE's investment in Safe Harbor Water Power Corporation to CGI. 5. The expected transfer of generating assets as described in this Exhibit including utility plant in service, accumulated depreciation reserves, construction work in progress, plant held for future use, and unamortized investment tax credits. 6. The elimination of the remaining $37.5 million unamortized balance of the regulatory asset relating to the $150 million reduction of electric generation plant that will be fully amortized prior to the actual generation asset transfer under the terms of the Restructuring Order. 7. The expected reduction to current liabilities from eliminating approximately $4 million of accrued interest relating to the transferred tax-exempt debt described in this Exhibit. 8. The anticipated transfer of the $20 million current (included in other current liabilities) and the $9 million non-current (included in other deferred credits and other liabilities) portions of liabilities accrued in connection with certain purchased power contracts that will become the responsibility of the nonregulated generation business. 9. The reflection of the approximate impact on accumulated deferred income taxes of the transfer of the generation assets and nuclear decommissioning, and the reflection of the Restructuring Order as described in this Exhibit. 10. The expected transfer of the tax-exempt debt as described in this Exhibit. 11. The anticipated net reduction in BGE's common shareholder's equity relating to the other balance sheet adjustments described above. 4 FORWARD-LOOKING STATEMENTS We make statements in this Exhibit 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 BGE's future performance and are subject to risks, uncertainties, and other important factors that could cause its actual performance or achievements to be materially different from those projected. These risks, uncertainties, and factors include, but are not limited to: o general economic, business, and regulatory conditions, o energy supply and demand, o competition, o federal and state regulations, o availability, terms, and use of capital, o environmental issues, o weather, o implications of the Restructuring Order issued by the Maryland PSC, o loss of revenues due to customers choosing alternate suppliers, o inability to recover all costs associated with providing electric retail customers service during the electric rate freeze period, and o implications from the transfer of BGE's generation assets to nonregulated subsidiaries of Constellation Energy. Given these uncertainties, you should not place undue reliance on these forward-looking statements. Please see BGE's 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. 5 Baltimore Gas and Electric Company Unaudited Condensed Pro Forma Statement of Income Three Months Ended March 31, 2000
As Reported Adjustments Pro Forma ----------- ----------- ----------- (In Millions) Revenues Electric $ 524.6 $ (76.0) (1,2,3) $ 448.6 Gas 195.1 - 195.1 Nonregulated 1.0 - 1.0 ----------- ----------- ----------- Total Revenues 720.7 (76.0) 644.7 ----------- ------------ ----------- Operating Expenses Electric fuel and purchased energy 119.4 148.0 (4) 267.4 Gas purchased for resale 103.0 - 103.0 Operations and maintenance 177.6 (95.0) (5) 82.6 Nonregulated - selling, general, and administrative 0.6 - 0.6 Depreciation and amortization 126.1 (80.0) (6,7) 46.1 Taxes other than income taxes 60.1 (21.0) (8) 39.1 ----------- ------------ ----------- Total operating expenses 586.8 (48.0) 538.8 ----------- ------------ ----------- Income from Operations 133.9 (28.0) 105.9 Other Income 3.3 4.0 (9,10) 7.3 ----------- ------------ ----------- Income Before Fixed Charges and Income Taxes 137.2 (24.0) 113.2 Fixed Charges 47.5 (3.0) (11) 44.5 ----------- ------------ ----------- Income Before Income Taxes 89.7 (21.0) 68.7 ----------- ------------ ----------- Income Taxes Income taxes 37.5 (9.0) (12) 28.5 Investment tax credit adjustments (2.0) 1.0 (13) (1.0) ----------- ------------ ----------- Total income taxes 35.5 (8.0) 27.5 ----------- ------------ ----------- Net Income $ 54.2 $ (13.0) $ 41.2 =========== ============ ===========
6 Baltimore Gas and Electric Company Unaudited Condensed Pro Forma Statement of Income Twelve Months Ended December 31, 1999 (Revised)
As Reported Adjustments Pro Forma ----------- ------------ ----------- (In Millions) Revenues Electric $ 2,259.5 $ (330.0) (1,2,3) $ 1,929.5 Gas 485.3 - 485.3 Nonregulated 283.5 - 283.5 ----------- ------------ ----------- Total Revenues 3,028.3 (330.0) 2,698.3 ----------- ------------ ----------- Operating Expenses Electric fuel and purchased energy 486.8 700.0 (4) 1,186.8 Gas purchased for resale 233.7 - 233.7 Operations and maintenance 728.8 (390.0) (5) 338.8 Nonregulated - selling, general, and administrative 222.1 - 222.1 Depreciation and amortization 427.9 (240.0) (6,7) 187.9 Taxes other than income taxes 224.7 (85.0) (8) 139.7 ----------- ------------ ----------- Total operating expenses 2,324.0 (15.0) 2,309.0 ----------- ------------ ----------- Income from Operations 704.3 (315.0) 389.3 Other Income 8.4 15.0 (9,10) 23.4 ----------- ------------ ----------- Income Before Fixed Charges and Income Taxes 712.7 (300.0) 412.7 Fixed Charges 205.9 (13.0) (11) 192.9 ----------- ------------ ----------- Income Before Income Taxes 506.8 (287.0) 219.8 ----------- ------------ ----------- Income Taxes Income taxes 186.9 (107.0) (12) 79.9 Investment tax credit adjustments (8.5) 6.0 (13) (2.5) ----------- ------------ ----------- Total income taxes 178.4 (101.0) 77.4 ----------- ------------ ----------- Income Before Extraordinary Loss $ 328.4 $ (186.0) $ 142.4 =========== ============ ===========
7 Baltimore Gas and Electric Company and Subsidiaries Unaudited Condensed Pro Forma Balance Sheet March 31, 2000
As Reported Adjustments Pro Forma ----------- ------------ ----------- (In Millions) ASSETS Current Assets Fuel stocks $ 69.6 $ (60.0)(1) $ 9.6 Materials and supplies 138.6 (100.0)(1) 38.6 Current portion of notes receivable, affiliated companies - 366.0 (2) 366.0 Interest receivable, affiliated companies - 4.0 (2) 4.0 Other current assets 355.9 - 355.9 ----------- ------------ ----------- Total current assets 564.1 210.0 774.1 ----------- ------------ ----------- Investments And Other Assets Notes receivable, affiliated companies - 60.0 (2) 60.0 Nuclear decommissioning trust fund 222.7 (222.7)(3) - Safe Harbor Water Power Corporation 34.5 (34.5)(4) - Other investments and other assets 161.9 - 161.9 ------------ ------------ ----------- Total investments and other assets 419.1 (197.2) 221.9 ------------ ------------ ----------- Utility Plant Plant in service Electric 7,123.4 (3,980.0)(5) 3,143.4 Gas 970.2 - 970.2 Common 562.2 (45.0)(5) 517.2 ------------ ------------ ----------- Total plant in service 8,655.8 (4,025.0) 4,630.8 Accumulated depreciation (3,522.1) 1,870.0 (5) (1,652.1) ------------ ------------ ----------- Net plant in service 5,133.7 (2,155.0) 2,978.7 Construction work in progress 241.1 (145.0)(5) 96.1 Nuclear fuel (net of amortization) 123.4 (123.4)(1) - Plant held for future use 12.9 (3.2)(5 9.7 ------------ ------------ ----------- Net utility plant 5,511.1 (2,426.6) 3,084.5 ------------ ------------ ----------- Deferred Charges 639.8 (37.5)(6) 602.3 ------------ ------------ ----------- Total Assets $ 7,134.1 $ (2,451.3) $ 4,682.8 ============ ============ =========== LIABILITIES AND CAPITALIZATION Current Liabilities Current portions of long-term debt $ 543.9 $ - $ 543.9 Other current liabilities 509.8 (24.0)(7,8) 485.8 ------------ ------------ ----------- Total current liabilities 1,053.7 (24.0) 1,029.7 ------------ ------------ ----------- Deferred Credits And Other Liabilities Deferred income taxes 1,010.4 (470.0)(9) 540.4 Deferred investment tax credits 107.5 (82.0)(5) 25.5 Other deferred credits and other liabilities 309.1 (9.0)(8) 300.1 ------------ ------------ ----------- Total deferred credits and other liabilities 1,427.0 (561.0) 866.0 ------------ ------------ ----------- Long-Term Debt First refunding mortgage bonds of BGE 1,321.7 - 1,321.7 Other long-term debt of BGE 1,068.9 (278.0)(10) 790.9 Company obligated mandatorily redeemable trust preferred securities of subsidiary trust holding solely 7.16% debentures of BGE 250.0 - 250.0 Long-term debt of nonregulated businesses 32.0 - 32.0 Unamortized discount and premium (10.1) - (10.1) Current portion of long-term debt (543.9) - (543.9) ------------- ----------- ---------- Total long-term debt 2,118.6 (278.0) 1,840.6 ------------- ----------- ---------- BGE Preference Stock Not Subject To Mandatory Redemption 190.0 - 190.0 ------------- ----------- ---------- Common Shareholder's Equity 2,344.8 (1,588.3)(11) 756.5 ------------ ------------ ---------- Total Capitalization 4,653.4 (1,866.3) 2,787.1 ------------ ------------ ---------- Total Liabilities And Capitalization $ 7,134.1 $(2,451.3) $ 4,682.8 ============ ============ ==========
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