-----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, VyzqvWWko9V70o0u1Da2hN78Xm9OIzZEoG8f0gN+/tiQjCUiN+kxQbVrXlDMOHuh PqbF0SDu8Yi/kpfhmrwkCg== 0001004440-99-000025.txt : 19990816 0001004440-99-000025.hdr.sgml : 19990816 ACCESSION NUMBER: 0001004440-99-000025 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 5 CONFORMED PERIOD OF REPORT: 19990630 FILED AS OF DATE: 19990813 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: 99687396 BUSINESS ADDRESS: STREET 1: 39 WEST LEXINGTON ST CITY: BALTIMORE STATE: MD ZIP: 21201 BUSINESS PHONE: 4102345685 MAIL ADDRESS: STREET 1: 39 WEST LEXINGTON ST CITY: BALTIMORE STATE: MD ZIP: 21201 FORMER COMPANY: FORMER CONFORMED NAME: CONSTELLATION ENERGY CORP DATE OF NAME CHANGE: 19951220 FORMER COMPANY: FORMER CONFORMED NAME: RH ACQUISITION CORP DATE OF NAME CHANGE: 19951205 10-Q 1 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 June 30, 1999 Commission Exact name of registrant IRS Employer file 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) 39 W. Lexington Street Baltimore, Maryland 21201 ------------------------------------------------ (Address of principal executive offices) (Zip Code) 410-783-5920 (Registrants' telephone number, including area code) Not Applicable (Former name,former address and former fiscal year,if changed since last report) Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months, and (2) have been subject to such filing requirements for the past 90 days. Yes X No Common Stock, without par value - 149,556,416 shares outstanding of Constellation Energy Group, Inc. on July 31, 1999. 1 Table of Contents
Part I. Financial Information Page Item 1. Consolidated 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 Introduction........................................................................... 17 Results of Operations.................................................................. 18 Financial Condition.................................................................... 28 Capital Resources...................................................................... 29 Other Matters.......................................................................... 31 Item 3. Quantitative and Qualitative Disclosures About Market Risk.................................. 34 Part II. Other Information Item 1. Legal Proceedings........................................................................... 35 Item 2. Changes in Securities and Use of Proceeds................................................... 35 Item 4. Submission of Matters to a Vote of Security Holders......................................... 37 Item 5. Other Information........................................................................... 38 Item 6. Exhibits and Reports on Form 8-K............................................................ 38 Signatures........................................................................................... 39 Exhibit Index........................................................................................ 40 Constellation Energy Group, Inc. Computation of Ratio of Earnings to Fixed Charges................... 41 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....................................... 42
2 CONSTELLATION ENERGY GROUP, INC. AND SUBSIDIARIES PART I. FINANCIAL INFORMATION Item 1. Financial Statements Consolidated Statements of Income (Unaudited)
Three Months Ended June 30, Six Months Ended June 30, 1999 1998 1999 1998 ---------- ---------- ----------- ---------- (In Millions, Except Per-Share Amounts) Revenues Electric $ 533.0 $ 525.2 $ 1,046.0 $ 1,024.3 Gas 79.9 82.0 272.7 262.6 Diversified businesses 207.1 160.4 433.6 346.8 ---------- ---------- ----------- ---------- Total revenues 820.0 767.6 1,752.3 1,633.7 ---------- ---------- ----------- ---------- Expenses Other Than Fixed Charges and Income Taxes Electric fuel and purchased energy 120.0 115.6 241.2 242.1 Gas purchased for resale 33.0 32.2 135.1 130.4 Operations 135.2 139.7 270.5 265.8 Maintenance 53.6 57.9 102.4 92.1 Diversified businesses - selling, general, and administrative 171.7 126.8 348.0 270.9 Depreciation and amortization 90.8 89.6 181.1 186.1 Taxes other than income taxes 51.8 49.6 112.1 106.6 ---------- ---------- ----------- ---------- Total expenses other than fixed charges and income taxes 656.1 611.4 1,390.4 1,294.0 ---------- ---------- ----------- ---------- Income From Operations 163.9 156.2 361.9 339.7 Other Income 5.2 0.9 4.5 2.8 ---------- ---------- ----------- ---------- Income Before Fixed Charges and Income Taxes 169.1 157.1 366.4 342.5 ---------- ---------- ----------- ---------- Fixed Charges Interest expense (net) 58.2 58.9 119.3 118.5 BGE preference stock dividends 3.4 5.8 6.9 11.6 ---------- ---------- ----------- ---------- Total fixed charges 61.6 64.7 126.2 130.1 ---------- ---------- ----------- ---------- Income Before Income Taxes 107.5 92.4 240.2 212.4 ---------- ---------- ----------- ---------- Income Taxes Current 26.4 30.7 75.9 88.1 Deferred 15.3 6.1 17.8 (3.9) Investment tax credit adjustments (2.2) (1.8) (4.3) (3.6) ---------- ---------- ----------- ---------- Total income taxes 39.5 35.0 89.4 80.6 ---------- ---------- ----------- ---------- Net Income $ 68.0 $ 57.4 $ 150.8 $ 131.8 ========== ========== =========== ========== Earnings Applicable to Common Stock $ 68.0 $ 57.4 $ 150.8 $ 131.8 ========== ========== =========== ========== Average Shares of Common Stock Outstanding 149.6 148.3 149.6 148.1 Earnings Per Common Share and Earnings Per Common Share - Assuming Dilution $0.45 $0.39 $1.01 $0.89 Dividends Declared Per Common Share $0.42 $0.42 $0.84 $0.83 Consolidated Statements of Comprehensive Income (Unaudited) Net Income $ 68.0 $ 57.4 $ 150.8 $ 131.8 Other comprehensive loss, net of taxes (8.3) (1.0) (11.5) (0.1) ---------- ---------- ----------- ---------- Comprehensive Income $ 59.7 $ 56.4 $ 139.3 $ 131.7 ========== ========== =========== ==========
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
June 30, December 31, 1999* 1998 -------------- -------------- (In Millions) ASSETS Current Assets Cash and cash equivalents $ 103.4 $ 173.7 Accounts receivable (net of allowance for uncollectibles of $21.5 and $20.3 respectively) 482.1 401.8 Trading securities 109.4 119.7 Fuel stocks 69.1 85.4 Materials and supplies 149.5 145.1 Prepaid taxes other than income taxes 3.5 68.8 Assets from energy trading activities 317.8 160.2 Other 57.0 21.4 -------------- -------------- Total current assets 1,291.8 1,176.1 -------------- -------------- Investments and Other Assets Real estate projects and investments 319.2 353.9 Power projects 669.5 656.8 Financial investments 172.6 198.0 Nuclear decommissioning trust fund 199.2 181.4 Net pension asset 96.6 108.0 Other 262.1 243.3 -------------- -------------- Total investments and other assets 1,719.2 1,741.4 -------------- -------------- Utility Plant Plant in service Electric 6,988.2 6,890.3 Gas 945.8 921.3 Common 561.9 552.8 -------------- -------------- Total plant in service 8,495.9 8,364.4 Accumulated depreciation (3,193.5) (3,087.5) -------------- -------------- Net plant in service 5,302.4 5,276.9 Construction work in progress 200.5 223.0 Nuclear fuel (net of amortization) 129.2 132.5 Plant held for future use 13.0 24.3 -------------- -------------- Net utility plant 5,645.1 5,656.7 -------------- -------------- Deferred Charges Regulatory assets (net) 519.8 565.7 Other 58.2 55.1 -------------- -------------- Total deferred charges 578.0 620.8 -------------- -------------- TOTAL ASSETS $ 9,234.1 $ 9,195.0 ============== ==============
* Unaudited See Notes to Consolidated Financial Statements. Certain prior period amounts have been reclassified to conform with the current period's presentation. 4 CONSTELLATION ENERGY GROUP, INC. AND SUBSIDIARIES PART I. FINANCIAL INFORMATION (Continued) Item 1. Financial Statements Consolidated Balance Sheets
June 30, December 31, 1999* 1998 -------------- -------------- (In Millions) LIABILITIES AND CAPITALIZATION Current Liabilities Short-term borrowings $ 109.3 $ - Current portions of long-term debt and preference stock 474.3 541.7 Accounts payable 317.4 249.6 Customer deposits 38.3 35.5 Accrued taxes 3.0 6.5 Accrued interest 55.9 58.6 Dividends declared 66.3 66.1 Accrued vacation costs 36.3 34.7 Liabilities from energy trading activities 180.0 126.2 Other 35.1 45.3 -------------- -------------- Total current liabilities 1,315.9 1,164.2 -------------- -------------- Deferred Credits and Other Liabilities Deferred income taxes 1,314.3 1,309.1 Postretirement and postemployment benefits 231.9 217.0 Deferred investment tax credits 113.7 118.0 Decommissioning of federal uranium enrichment facilities 30.8 30.8 Other 69.4 56.3 -------------- -------------- Total deferred credits and other liabilities 1,760.1 1,731.2 -------------- -------------- Long-term Debt BGE first refunding mortgage bonds 1,429.2 1,554.2 BGE other long-term debt 1,000.8 1,000.8 BGE obligated mandatorily redeemable trust preferred securities 250.0 250.0 Diversified businesses long-term debt 762.6 870.2 Unamortized discount and premium (11.6) (12.4) Current portion of long-term debt (467.3) (534.7) -------------- -------------- Total long-term debt 2,963.7 3,128.1 -------------- -------------- BGE Redeemable Preference Stock 7.0 7.0 Current portion of BGE redeemable preference stock (7.0) (7.0) -------------- -------------- Total BGE redeemable preference stock - - -------------- -------------- BGE Preference Stock Not Subject to Mandatory Redemption 190.0 190.0 -------------- -------------- Common Shareholders' Equity Common stock 1,494.3 1,485.1 Retained earnings 1,515.5 1,490.3 Accumulated other comprehensive income (loss) (5.4) 6.1 -------------- -------------- Total common shareholders' equity 3,004.4 2,981.5 -------------- -------------- Total capitalization 6,158.1 6,299.6 -------------- -------------- TOTAL LIABILITIES AND CAPITALIZATION $ 9,234.1 $ 9,195.0 ============== ==============
* Unaudited See Notes to Consolidated Financial Statements. Certain prior period amounts have been reclassified to conform with the current period's presentation. 5 CONSTELLATION ENERGY GROUP, INC. AND SUBSIDIARIES PART I. FINANCIAL INFORMATION (Continued) Item 1. Financial Statements Consolidated Statements of Cash Flows (Unaudited)
Six Months Ended June 30, -------------------------------- 1999 1998 ------------- ------------ (In Millions) Cash Flows From Operating Activities Net income $ 150.8 $ 131.8 Adjustments to reconcile to net cash provided by operating activities Depreciation and amortization 208.4 209.0 Deferred income taxes 17.8 (3.9) Investment tax credit adjustments (4.3) (3.6) Deferred fuel costs 7.1 20.4 Accrued pension and postemployment benefits 28.7 10.6 Equity in earnings of affiliates and joint ventures (net) 26.2 (11.9) Changes in assets from energy trading activities (157.6) (341.9) Changes in liabilities from energy trading activities 53.8 324.5 Changes in other current assets (24.4) 104.9 Changes in other current liabilities 68.4 (18.2) Other (4.7) (18.3) ------------- ------------ Net cash provided by operating activities 370.2 403.4 ------------- ------------ Cash Flows From Investing Activities Utility capital expenditures (182.3) (169.9) Contributions to nuclear decommissioning trust fund (8.8) (8.8) Purchases of marketable equity securities (12.4) (16.5) Sales of marketable equity securities 9.8 18.7 Other financial investments 8.5 13.6 Real estate projects and investments 40.7 26.9 Power projects (31.8) (82.1) Other (19.2) (31.2) ------------- ------------ Net cash used in investing activities (195.5) (249.3) ------------- ------------ Cash Flows From Financing Activities Proceeds from issuance of Short-term borrowings 1,029.3 1,476.1 Long-term debt 127.5 391.4 Common stock 9.6 12.6 Repayments of short-term borrowings (920.0) (1,719.7) Reacquisition of long-term debt (360.5) (59.1) Redemption of preference stock - (3.0) Common stock dividends paid (125.5) (121.2) Other (5.4) 8.7 ------------- ------------ Net cash used in financing activities (245.0) (14.2) ------------- ------------ Net (Decrease) Increase in Cash and Cash Equivalents (70.3) 139.9 Cash and Cash Equivalents at Beginning of Period 173.7 162.6 ------------- ------------ Cash and Cash Equivalents at End of Period $ 103.4 $ 302.5 ============= ============ Other Cash Flow Information: Interest paid (net of amounts capitalized) $ 120.4 $ 114.7 Income taxes paid $ 101.0 $ 89.9
See Notes to Consolidated Financial Statements. Certain prior period amounts have been reclassified to conform with the current period's presentation. 6 BALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARIES PART I. FINANCIAL INFORMATION (Continued) Item 1. Financial Statements Consolidated Statements of Income (Unaudited)
Three Months Ended June 30, Six Months Ended June 30, 1999 1998 1999 1998 ---------- ---------- ----------- ---------- (In Millions, Except Per-Share Amounts) Revenues Electric $ 533.1 $ 525.2 $ 1,046.1 $ 1,024.3 Gas 81.6 82.0 274.4 262.6 Diversified businesses 54.5 160.4 281.0 346.8 ---------- ---------- ----------- ---------- Total revenues 669.2 767.6 1,601.5 1,633.7 ---------- ---------- ----------- ---------- Expenses Other Than Interest and Income Taxes Electric fuel and purchased energy 124.2 115.6 245.4 242.1 Gas purchased for resale 33.0 32.2 135.1 130.4 Operations 134.9 139.7 270.2 265.8 Maintenance 52.9 57.9 101.8 92.1 Diversified businesses - selling, general, and administrative 43.9 126.8 220.2 270.9 Depreciation and amortization 88.3 89.6 178.5 186.1 Taxes other than income taxes 51.1 49.6 111.4 106.6 ---------- ---------- ----------- ---------- Total expenses other than interest and income taxes 528.3 611.4 1,262.6 1,294.0 ---------- ---------- ----------- ---------- Income From Operations 140.9 156.2 338.9 339.7 ---------- ---------- ----------- ---------- Other Income Allowance for equity funds used during construction 2.0 1.6 3.7 3.2 Equity in earnings of Safe Harbor Water Power Corporation 1.3 1.2 2.6 2.5 Net other income and (deductions) 0.7 (1.9) (3.0) (2.9) ---------- ---------- ----------- ---------- Total other income 4.0 0.9 3.3 2.8 ---------- ---------- ----------- ---------- Income Before Interest and Income Taxes 144.9 157.1 342.2 342.5 ---------- ---------- ----------- ---------- Interest Expense Interest charges 51.8 60.4 114.1 122.2 Capitalized interest (0.1) (0.6) (0.4) (2.0) Allowance for borrowed funds used during construction (1.1) (0.9) (2.0) (1.7) ---------- ---------- ----------- ---------- Net interest expense 50.6 58.9 111.7 118.5 ---------- ---------- ----------- ---------- Income Before Income Taxes 94.3 98.2 230.5 224.0 ---------- ---------- ----------- ---------- Income Taxes Current 39.0 30.7 88.6 88.1 Deferred (3.8) 6.1 (1.3) (3.9) Investment tax credit adjustments (2.1) (1.8) (4.3) (3.6) ---------- ---------- ----------- ---------- Total income taxes 33.1 35.0 83.0 80.6 ---------- ---------- ----------- ---------- Net Income 61.2 63.2 147.5 143.4 Preference Stock Dividends 3.4 5.8 6.9 11.6 ---------- ---------- ----------- ---------- Earnings Applicable to Common Stock $ 57.8 $ 57.4 $ 140.6 $ 131.8 ========== ========== =========== ========== Consolidated Statements of Comprehensive Income (Unaudited) Net Income $ 61.2 $ 63.2 $ 147.5 $ 143.4 Other comprehensive loss, net of taxes (0.2) (1.0) (3.4) (0.1) ---------- ---------- ----------- ---------- Comprehensive Income $ 61.0 $ 62.2 $ 144.1 $ 143.3 ========== ========== =========== ==========
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
June 30, December 31, 1999* 1998 -------------- -------------- (In Millions) ASSETS Current Assets Cash and cash equivalents $ 13.4 $ 173.7 Accounts receivable (net of allowance for uncollectibles of $13.0 and $20.3 respectively) 304.0 401.8 Trading securities - 119.7 Fuel stocks 69.1 85.4 Materials and supplies 141.1 145.1 Prepaid taxes other than income taxes 3.5 68.8 Assets from energy trading activities - 160.2 Other 33.1 21.4 -------------- -------------- Total current assets 564.2 1,176.1 -------------- -------------- Investments and Other Assets Real estate projects and investments - 353.9 Power projects - 656.8 Financial investments - 198.0 Nuclear decommissioning trust fund 199.2 181.4 Net pension asset 96.6 108.0 Safe Harbor Water Power Corporation 34.5 34.4 Senior living facilities - 93.5 Other 56.3 115.4 -------------- -------------- Total investments and other assets 386.6 1,741.4 -------------- -------------- Utility Plant Plant in service Electric 6,988.2 6,890.3 Gas 945.8 921.3 Common 561.9 552.8 -------------- -------------- Total plant in service 8,495.9 8,364.4 Accumulated depreciation (3,193.5) (3,087.5) -------------- -------------- Net plant in service 5,302.4 5,276.9 Construction work in progress 200.5 223.0 Nuclear fuel (net of amortization) 129.2 132.5 Plant held for future use 13.0 24.3 -------------- -------------- Net utility plant 5,645.1 5,656.7 -------------- -------------- Deferred Charges Regulatory assets (net) 519.8 565.7 Other 49.2 55.1 -------------- -------------- Total deferred charges 569.0 620.8 -------------- -------------- TOTAL ASSETS $ 7,164.9 $ 9,195.0 ============== ==============
* 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
June 30, December 31, 1999* 1998 -------------- -------------- (In Millions) LIABILITIES AND CAPITALIZATION Current Liabilities Short-term borrowings $ 109.3 $ - Current portions of long-term debt and preference stock 197.4 541.7 Accounts payable 188.3 249.6 Customer deposits 38.3 35.5 Accrued taxes 2.0 6.5 Accrued interest 49.0 58.6 Dividends declared 3.4 66.1 Accrued vacation costs 36.4 34.7 Liabilities from energy trading activities - 126.2 Other 18.6 45.3 -------------- -------------- Total current liabilities 642.7 1,164.2 -------------- -------------- Deferred Credits and Other Liabilities Deferred income taxes 1,059.9 1,309.1 Postretirement and postemployment benefits 223.7 217.0 Deferred investment tax credits 113.7 118.0 Decommissioning of federal uranium enrichment facilities 30.8 30.8 Other 18.9 56.3 -------------- -------------- Total deferred credits and other liabilities 1,447.0 1,731.2 -------------- -------------- Long-term Debt First refunding mortgage bonds of BGE 1,429.2 1,554.2 Other long-term debt of BGE 1,000.8 1,000.8 Company obligated mandatorily redeemable trust preferred securities 250.0 250.0 Long-term debt of diversified businesses 33.1 870.2 Unamortized discount and premium (11.6) (12.4) Current portion of long-term debt (190.4) (534.7) -------------- -------------- Total long-term debt 2,511.1 3,128.1 -------------- -------------- Redeemable Preference Stock 7.0 7.0 Current portion of redeemable preference stock (7.0) (7.0) -------------- -------------- Total redeemable preference stock - - -------------- -------------- Preference Stock Not Subject to Mandatory Redemption 190.0 190.0 -------------- -------------- Common Shareholder's Equity Common stock 1,494.3 1,485.1 Retained earnings 879.8 1,490.3 Accumulated other comprehensive income - 6.1 -------------- -------------- Total common shareholder's equity 2,374.1 2,981.5 -------------- -------------- Total capitalization 5,075.2 6,299.6 -------------- -------------- TOTAL LIABILITIES AND CAPITALIZATION $ 7,164.9 $ 9,195.0 ============== ==============
* 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)
Six Months Ended June 30, ------------------------------- 1999 1998 ------------ ------------ (In Millions) Cash Flows From Operating Activities Net income $ 147.5 $ 143.4 Adjustments to reconcile to net cash provided by operating activities Depreciation and amortization 204.4 209.0 Deferred income taxes (1.3) (3.9) Investment tax credit adjustments (4.3) (3.6) Deferred fuel costs 7.1 20.4 Accrued pension and postemployment benefits 28.6 10.6 Allowance for equity funds used during construction (3.7) (3.2) Equity in earnings of affiliates and joint ventures (net) 29.1 (11.9) Changes in assets from energy trading activities (120.1) (341.9) Changes in liabilities from energy trading activities 76.3 324.5 Changes in other current assets 65.4 104.9 Changes in other current liabilities (14.1) (18.2) Other (0.6) (15.1) ------------ ------------ Net cash provided by operating activities 414.3 415.0 ------------ ------------ Cash Flows From Investing Activities Utility construction expenditures (including AFC) (166.8) (143.8) Allowance for equity funds used during construction 3.7 3.2 Nuclear fuel expenditures (18.5) (18.5) Deferred energy conservation expenditures (0.7) (10.8) Contributions to nuclear decommissioning trust fund (8.8) (8.8) Purchases of marketable equity securities (9.2) (16.5) Sales of marketable equity securities 6.0 18.7 Other financial investments 6.7 13.6 Real estate projects and investments 22.0 26.9 Power projects (17.9) (82.1) Other (12.4) (31.2) ------------ ------------ Net cash used in investing activities (195.9) (249.3) ------------ ------------ Cash Flows From Financing Activities Proceeds from issuance of Short-term borrowings 1,029.3 1,476.1 Long-term debt 107.6 391.4 Common stock 9.6 12.6 Repayments of short-term borrowings (920.0) (1,719.7) Reacquisition of long-term debt (343.9) (59.1) Redemption of preference stock - (3.0) Common stock dividends paid (125.5) (121.2) Preference stock dividends paid (6.9) (11.6) Distribution of cash to Constellation Energy (128.2) - Other (0.7) 8.7 ------------ ------------ Net cash used in financing activities (378.7) (25.8) ------------ ------------ Net (Decrease) Increase in Cash and Cash Equivalents (160.3) 139.9 Cash and Cash Equivalents at Beginning of Period 173.7 162.6 ------------ ------------ Cash and Cash Equivalents at End of Period $ 13.4 $ 302.5 ============ ============ Other Cash Flow Information: Interest paid (net of amounts capitalized) $ 107.4 $ 114.7 Income taxes paid $ 99.3 $ 89.9
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 which 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 Group, Inc. (Constellation Energy) became the holding company for Baltimore Gas and Electric Company (BGE) and BGE's former subsidiary Constellation Enterprises, Inc. BGE's outstanding common stock automatically became shares of common stock of Constellation Energy. BGE's debt securities, BGE 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, and Constellation Enterprises, Inc. 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. Information by Operating Segment - --------------------------------
Energy Other Unallocated Electric Gas Services Diversified Corporate Business Business Businesses Businesses Items (a) Eliminations Consolidated ------------ ------------ ------------- --------------- -------------- ------------- --------------- For the three months ended June 30, (in millions) 1999 Unaffiliated revenues $ 533.0 $ 79.9 $ 181.2 $ 25.9 $ - $ - $ 820.0 Intersegment revenues 0.1 2.4 11.7 - - (14.2) - ----------- ------------ ------------- --------------- -------------- ------------- --------------- Total revenues 533.1 82.3 192.9 25.9 - (14.2) 820.0 Net income (loss) 54.7 0.6 18.9 (5.1) (0.8) (0.3) 68.0 Segment assets 6,246.1 877.3 1,460.8 763.0 (19.0) (94.1) 9,234.1 1998 Unaffiliated revenues $ 525.2 $ 82.0 $ 118.6 $ 41.8 $ - $ - $ 767.6 Intersegment revenues 0.1 - 0.4 0.1 - (0.6) - ----------- ------------ ------------- --------------- -------------- ------------- --------------- Total revenues 525.3 82.0 119.0 41.9 - (0.6) 767.6 Net income (loss) 48.0 1.7 8.5 (0.5) - (0.3) 57.4 Segment assets 6,416.4 892.2 1,168.7 880.9 (28.3) (8.5) 9,321.4
11
Energy Other Unallocated Electric Gas Services Diversified Corporate Business Business Businesses Businesses Items (a) Eliminations Consolidated ------------ ------------ ------------- --------------- -------------- ------------- --------------- For the six months ended June 30, (in millions) 1999 Unaffiliated revenues $1,046.0 $272.7 $ 358.7 $ 74.9 $ - $ - $1,752.3 Intersegment revenues 0.5 4.5 12.3 (0.3) - (17.0) - ----------- ------------ ------------- --------------- -------------- ------------- --------------- Total revenues 1,046.5 277.2 371.0 74.6 - (17.0) 1,752.3 Net income (loss) 101.1 22.2 35.0 (6.7) (0.8) - 150.8 Segment assets 6,246.1 877.3 1,460.8 763.0 (19.0) (94.1) 9,234.1 1998 Unaffiliated revenues $1,024.3 $262.6 $ 234.9 $111.9 $ - $ - $1,633.7 Intersegment revenues 0.1 - 0.5 0.3 - (0.9) - ----------- ------------ ------------- --------------- -------------- ------------- --------------- Total revenues 1,024.4 262.6 235.4 112.2 - (0.9) 1,633.7 Net income 93.4 17.4 18.5 2.5 - - 131.8 Segment assets 6,416.4 892.2 1,168.7 880.9 (28.3) (8.5) 9,321.4
(a) A holding company for our diversified businesses does not allocate the items presented in the table to our Energy Services and Other Diversified 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, 1999 through the date of this report, we issued a total of 310,775 shares of common stock, without par value, under the Shareholder Investment Plan. Net proceeds were about $9.6 million. In June 1999, Constellation Energy arranged a $135 million revolving credit agreement for short-term financial needs, including letters of credit. This facility replaced a similar facility at one of Constellation Energy's diversified businesses. BGE - --- BGE issued the following medium-term notes during the period from January 1, 1999 through the date of this report: Date Net Principal Issued Proceeds --------- ------ -------- (In millions) Series G - -------- Floating rate, due 2001 $60.0 3/99 $59.9 Series H - -------- Floating rate, due 2001 27.0 3/99 26.9 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. Diversified Businesses - ---------------------- Please refer to the "Capital Requirements of our Diversified Businesses" section of Management's Discussion and Analysis on page 30 for information about the debt of our diversified businesses. Commitments - ----------- In 1998, Constellation Power Source, Inc., our power marketing and trading business, and Goldman, Sachs Capital Partners II L.P., an affiliate of Goldman, Sachs & Co., formed Orion Power Holdings, Inc. to acquire electric generating plants in the United States and Canada. Constellation Power Source owns a minority interest in Orion, and has committed to contribute up to $175 million in equity to fund its investment in Orion. To date, Constellation Power Source has funded $101 million of this commitment. 12 Environmental Matters - --------------------- 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 must be implemented by January 1, 2000. We expect to meet the compliance requirements through a combination of switching fuels and allowance trading. Title I addresses NOx emissions. The Maryland Department of the Environment (MDE) issued NOx regulations effective June 1, 1998. The MDE regulations require major NOx sources to reduce NOx emissions up to 65% by May 1999. On February 9, 1999, the Baltimore City Circuit Court ordered the MDE to issue a new compliance date to meet their 65% emissions reduction regulations. On July 16, 1999, the MDE issued a new compliance date of May 1, 2000 for their NOx regulations. We are currently negotiating with the MDE to settle issues regarding the May 1, 2000 compliance date. 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 requires the reduction of NOx emissions up to 85% by 22 states (including Maryland and Pennsylvania). The 22 states must submit plans to the EPA by September 1999 showing how they will meet its new NOx emissions reduction requirements. This rule was appealed by several groups including utilities and states. On May 25, 1999, a federal appeals court postponed the September 1999 deadline. A final decision on the appeal is expected in early 2000. Based on the MDE and EPA regulations, we currently estimate that the additional controls needed at our generating plants to meet the 65% NOx emission reduction requirements will cost approximately $135 million. Through the date of this report, we have spent approximately $35 million to meet the 65% reduction requirements. We cannot estimate the cost for the 85% reduction requirements at this time, however, these costs could be material. In July 1997, the EPA published new National Ambient Air Quality Standards for very fine particulates and revised standards for ozone attainment. These standards may require increased controls at our fossil generating plants in the future. We cannot estimate the cost of these increased controls at this time because the states, including Maryland, still need to determine what reductions in pollutants will be necessary to meet the federal standards. The EPA and several state agencies have notified us that we are considered a potentially responsible party with respect to the cleanup of certain environmentally contaminated sites owned and operated by others. We cannot estimate the cleanup costs for all of these sites. We can, however, estimate that our current 15.42% 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 Site, also known as the Robb Tyler Dump. The EPA indicated that it is proceeding with plans to conduct a remedial investigation and feasibility study. This site was proposed for listing on the federal Superfund list in January 1999, but the list has not been finalized. Our records do not show that we sent waste to the site. 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. We discuss this site further in BGE's 1998 Annual Report on Form 10-K. We do not expect the cleanup costs of the remaining sites to have a material effect on our financial position or results of operations. 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 MDE. Based on the remedial action plans, the costs we consider to be probable to remedy the contamination are estimated to total $47 million in nominal dollars (including inflation). We have recorded these costs as a 13 liability on our Consolidated Balance Sheets and have deferred these costs, net of accumulated amortization and amounts recovered from insurance companies, as a regulatory asset. We discuss this further in Note 4 of BGE's 1998 Annual Report on Form 10-K. Through the date of this report, we have spent approximately $33 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 costs, 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 in nominal dollars ($7 million in current dollars, plus the impact of inflation at 3.1% over a period of up to 36 years). Our potential environmental liabilities and pending environmental actions are described further in BGE's 1998 Annual Report on Form 10-K under "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 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 $21.7 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 $9.71 billion under the provisions of the Price Anderson Act. If third party claims exceed $200 million (the amount of primary insurance), our share of the total liability for third party claims could be up to $176.2 million per incident. That amount would be payable at a rate of $20 million per year. Insurance for Worker Radiation Claims - ------------------------------------- As an operator of a commercial nuclear power plant in the United States, we are required to purchase insurance to cover radiation injury claims of certain nuclear workers. On January 1, 1998, a new insurance policy became effective for all operators requiring coverage for current operations. Waiving the right to make additional claims under the old policy was a condition for acceptance under the new policy. We describe both the old and new policies below. o BGE 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 nine 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. 14 Recoverability of Electric Fuel Costs - ------------------------------------- By law, we are allowed to recover our cost of electric fuel if the Maryland Public Service Commission (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. The Maryland PSC, under the Generating Unit Performance Program, measures annually whether we have maintained the productive capacity of our generating plants at reasonable levels. To do this, the program uses a system-wide generating performance target and an individual performance target for each base load generating unit. In fuel rate hearings, actual generating performance adjusted for planned outages will be compared first to the system-wide target. If that target is met, it should mean that the requirements of Maryland law have been met. If the system-wide target is not met, each unit's adjusted actual generating performance will be compared to its individual performance target to determine if the requirements of Maryland law have been met and, if not, to determine the basis for possibly imposing a penalty on BGE. Even if we meet these targets, parties to fuel rate hearings may still question whether we used all reasonable and cost-effective procedures to try to prevent an outage. If the Maryland PSC decides we were deficient in some way, the Maryland PSC may not allow us to recover the cost of replacement energy. 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. We discuss significant disallowances in prior years related to past outages at Calvert Cliffs in BGE's 1998 Annual Report on Form 10-K. BGE's electric fuel rate clause will be discontinued when electric generation is deregulated and, therefore, earnings will be affected by the changes in the cost of fuel and energy. We discuss competition and its impact on BGE's generation business further in the "Competition and Response to Regulatory Change" section of Management's Discussion and Analysis on page 20. California Power Purchase Agreements - ------------------------------------ Constellation Power, Inc. and subsidiaries and Constellation Investments, Inc. (whose power projects are managed by Constellation Power) have $304.3 million invested in 15 projects that sell electricity in California under power purchase agreements called "Interim Standard Offer No. 4" agreements. Earnings from these projects were $5.9 million, or $.04 per share, for the quarter ended June 30, 1999 and $13.9 million, or $.09 per share for the six months ended June 30, 1999. 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 "transition period" to describe the time frame when the 10-year periods for fixed energy rates expire for these 15 power generation projects and they begin supplying electricity at variable rates. The transition period for some of the projects began in 1996 and will continue for the remaining projects through 2000. The projects that have already transitioned to variable rates have had lower revenues under variable rates than they did under fixed rates. When the remaining projects transition to variable rates, we expect the revenues from those projects also to be lower than they are under fixed rates. 15 Our power projects business is pursuing alternatives for some of these power generation 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. At the date of this report, ten projects had already transitioned to variable rates. The remaining five projects that make the highest revenues will transition between September 1999 and December 2000. The projects which transition in 1999 contributed $1.3 million, or $.01 per share to the quarter ended June 30, 1999 earnings and $3.4 million, or $.02 per share for the six months ended June 30, 1999 earnings, while those changing over in 2000 contributed $4.6 million, or $.03 per share to the quarter ended June 30, 1999 earnings and $10.5 million, or $.07 per share for the six months ended June 30, 1999 earnings. We expect earnings to ultimately decrease by similar amounts as these projects transition. Constellation Real Estate - ------------------------- In August 1999, our senior-living facilities business announced that it has entered into an agreement to sell all but one of its senior-living facilities to Sunrise Assisted Living, Inc. Under the terms of the agreement, Sunrise will acquire twelve of our existing senior-living facilities, three facilities under construction, and several sites under development for $72.2 million in cash and $16.0 million in debt assumption. The sale is scheduled to close in the third quarter of 1999, provided that certain conditions have been fulfilled. We expect the sale to result in a write-down of approximately $4.0 million after-tax, or $.03 per share. In April 1999, Constellation Real Estate Group, Inc. (CREG) sold Church Street Station, our entertainment, dining, and retail complex in Orlando, Florida for $11.5 million, the approximate book value of the complex. Most of CREG's remaining real estate 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. CREG's real estate projects have continued to incur carrying costs and depreciation over the years. Additionally, CREG 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 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 diversified subsidiaries. Management's current real estate strategy is to hold each real estate project until we can realize a reasonable value for it. Management evaluates strategies for all its businesses, including real estate, on an ongoing basis. We anticipate that competing demands for our financial resources and changes in the utility industry will cause us to evaluate thoroughly all diversified business strategies on a regular basis so we use capital and other resources in a manner that is most beneficial. 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 projects. If we were to decide to sell our real estate projects, we could have write-downs. In addition, if we were to sell our remaining real estate 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. It may be helpful for you to understand when we are required, by accounting rules, to write down the value of a real estate project to market value. A write-down is required 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. 16 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. BGE is an electric and gas public utility company with a service territory in the City of Baltimore and in all or part of ten counties in Central Maryland. Constellation Enterprises is a holding company for several diversified businesses engaged primarily in energy services. Our energy services businesses are: o Constellation Power Source,(TM) Inc. -- our wholesale power marketing and trading business, o Constellation Power, Inc.,(TM) and Subsidiaries -- our power projects business, o Constellation Energy Source,(TM) Inc. -- our energy products and services business, o BGE Home Products & Services,(TM) Inc. and Subsidiaries -- our home products, commercial building systems, and residential and small commercial gas retail marketing business, and o District Chilled Water General Partnership (ComfortLink(R)) -- a general partnership in which BGE is a partner that provides cooling services for commercial customers in Baltimore. Constellation Enterprises, Inc. also has two other subsidiaries: o Constellation Investments,(TM) Inc. -- our financial investments business, and o Constellation Real Estate Group,(TM) Inc. -- our real estate and senior-living facilities business. This Quarterly Report on Form 10-Q is a combined report of Constellation Energy and BGE. As of April 30, 1999, the consolidated financial statements of Constellation Energy include the accounts of Constellation Energy, BGE and its subsidiaries, and Constellation Enterprises, Inc. and its subsidiaries. The consolidated financial statements of BGE include the accounts of BGE, ComfortLink, and BGE Capital Trust I. References in this report to "we" and "our" are to Constellation Energy and its subsidiaries, collectively. Reference in this report to the "utility business" is to BGE. The electric utility industry is undergoing rapid and substantial change. On April 8, 1999, legislation authorizing customer choice and competition among electric suppliers in Maryland was enacted. In addition, on June 29, 1999, BGE and a majority of the active parties involved in the electric restructuring proceeding filed a proposed settlement agreement with the Maryland Public Service Commission (Maryland PSC) that addresses the major issues surrounding electric restructuring. The proposed settlement agreement must be approved by the Maryland PSC to become effective. The regulatory environment (federal and state) for both electricity and natural gas is shifting toward customer choice. In Maryland, all gas customers will be able to choose suppliers of gas on November 1, 1999. Under the terms of the proposed settlement agreement, all electric customers, except a few commercial and industrial companies that have signed contracts with BGE, will be able to choose suppliers on July 1, 2000. These matters are discussed further in the "Competition and Response to Regulatory Change" section on page 20. 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. Constellation Energy will continue to invest in the growth of its power projects and power marketing and trading businesses with the objective of providing new sources of earnings in anticipation of lower electric utility revenues as competition is introduced into this industry in Maryland. On July 1, 2000, BGE's generation assets will be moved to a nonregulated subsidiary of Constellation Energy. 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 purchase or sale of generation assets, o mergers or acquisitions of utility or non-utility businesses, o spin-off or sale of one or more businesses, and o growth of earnings from other nonregulated businesses. 17 We cannot predict whether any of the strategies described above may actually occur, or what their effect on our financial condition or competitive position might be. Please refer to the "Forward Looking Statements" section. Additional detail on competition is included in BGE's 1998 Annual Report on Form 10-K under the heading "Electric Regulatory Matters and Competition." In this discussion and analysis, we explain the general financial condition and the results of operations for Constellation Energy 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 our expenditures for capital projects were in the current period and what we expect them to be in the future, and o where we expect to get cash for future capital expenditures. As you read this discussion and analysis, it may be helpful to refer to our Consolidated Statements of Income on page 3, which present the results of our operations for the quarters and six months ended June 30, 1999 and 1998. We analyze and explain the differences between periods in the specific line items of the Consolidated Statements of Income. Our analysis may be important to you in making decisions about your investments in Constellation Energy. Results of Operations for the Quarter and Six Months Ended June 30, 1999 Compared With the Same Periods of 1998 - -------------------------------------------------------------------------------- In this section, we discuss our earnings and the factors affecting them. We begin with a general overview, then separately discuss earnings for our utility business and for our diversified businesses. Overview - -------- Total Earnings per Share of Common Stock - ---------------------------------------- Quarter Ended Six Months Ended June 30 June 30 ---------------- -------------- 1999 1998 1999 1998 ------- ------- ------ ------ Utility business...... $ .37 $ .34 $ .82 $ .75 Diversified businesses .08 .05 .19 .14 ------- -------- ------- ------- Total earnings per share.......... $ .45 $ .39 $1.01 $ .89 ======= ======== ======= ======= Quarter Ended June 30, 1999 - --------------------------- Our total earnings for the quarter ended June 30, 1999 increased $10.6 million, or $.06 per share, compared to the same period of 1998. In the second quarter of 1999, we had higher utility earnings compared to the same period of 1998 mostly because we had lower operations and maintenance expenses this year. We discuss our utility earnings in more detail in the "Utility Business" section on page 19. In the second quarter of 1999, diversified business earnings increased compared to the same period of 1998 mostly because of higher earnings from our power marketing and trading business. Diversified business earnings would have been even higher except we had lower earnings from our financial investments business. We discuss our diversified business earnings further in the "Diversified Businesses" section beginning on page 26. Six Months Ended June 30, 1999 - ------------------------------ Our total earnings for the six months ended June 30, 1999 increased $19.0 million, or $.12 per share, compared to the same period of 1998. In the six months ended June 30, 1999, we had higher utility earnings compared to the same period of 1998 mostly because we sold more electricity and gas this year. Utility earnings would have been even higher except we had higher operations and maintenance expenses. We discuss our utility earnings in more detail in the "Utility Business" section on page 19. In the six months ended June 30, 1999, diversified business earnings increased compared to the same period of 1998 mostly because of higher earnings from our power marketing and trading business. Diversified business earnings would have been even higher except we had lower earnings from our financial investments business in 1999. We discuss our diversified business earnings further in the "Diversified Businesses" section beginning on page 26. 18 Utility Business - ---------------- Before we go into the details of our electric and gas operations, we believe it is important to discuss four factors that have a strong influence on our utility business performance: regulation, the weather, other factors including the condition of the economy in our service territory, and competition. Regulation by the Maryland PSC - ------------------------------ The Maryland PSC determines the rates we can charge our customers. Our rates consist of a "base rate" and a "fuel 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 the highest. Gas base rates are not affected by seasonal changes. From time to time, when necessary to cover increased costs, we ask the Maryland PSC for base rate increases. Similarly, other parties may petition the Maryland PSC to lower BGE's base rates. The Maryland PSC holds hearings to determine what changes, if any, should be made to base rates. The Maryland PSC has historically allowed us 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. Under the proposed settlement agreement, BGE's electric residential base rates are frozen at the current levels until July 1, 2000. At that time, electric residential base rates will be decreased and those reduced rates will be frozen until June 30, 2006. The Maryland PSC allows us to include in base 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. In addition, 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 (primarily with other utilities). 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 impacted most by the amount of electricity generated at our Calvert Cliffs Nuclear Power Plant (Calvert Cliffs) because the cost of nuclear fuel is cheaper than coal, gas, or oil. We discuss this in more detail in the "Electric Fuel Rate Clause" section on page 24 and in Note 1 of BGE's 1998 Annual Report on Form 10-K. Changes in the fuel rate normally do not affect earnings. However, if the Maryland PSC disallows recovery of any part of the fuel costs, our earnings are reduced. We discuss this in the "Recoverability of Electric Fuel Costs" section of the Notes to Consolidated Financial Statements on page 15. BGE's electric fuel rate clause will be discontinued when electric generation is deregulated and, therefore, earnings will be affected by the changes in the cost of fuel and energy. 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 refunded to or collected from our customers. This will occur over a period not to exceed twelve months from when the electric fuel rate clause no longer exists. At June 30, 1999, BGE's actual costs of fuel and energy were $5.9 million higher than the electric fuel rate revenues collected. We also 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. 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. 19 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. Effective March 1, 1998, the Maryland PSC allowed us to implement 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 and cooling degree days in the quarters and six months ended June 30, 1999 and 1998 and the percentage change in the number of degree days between these periods in the following table: Quarter Ended Six Months Ended June 30 June 30 --------------- ------------------ 1999 1998 1999 1998 -------- ------ -------- -------- Heating degree days... 517 463 2,907 2,485 Percent change compared to prior period 11.7% 17.0% Cooling degree days... 203 258 204 279 Percent change compared to prior period (21.3)% (26.9)% 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. Usage per customer refers to all other items impacting customer sales that cannot be separately measured. 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. Competition and Response to Regulatory Change - --------------------------------------------- Our electric and gas businesses are also affected by competition as discussed below. Electric Business - ----------------- 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 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. Major elements of the Act are: o Residential customer choice begins on July 1, 2000 for one third of our customers, and the next two thirds will be phased in over the following two years. o All commercial and industrial customers may choose electric suppliers beginning January 1, 2001. o Rates are frozen for all customers for four years after choice begins, at the rates in effect on June 30, 2000. o Residential customers are guaranteed a reduction of 3% to 7.5% of rates in effect on June 30, 1999 (exact amount to be determined by the Maryland PSC) on electric base rates effective July 1, 2000 for 4 years after choice begins. o Generation is deregulated beginning on July 1, 2000. o Existing utilities are responsible for the transmission and delivery of electricity. o The Maryland PSC continues to have the authority to mandate cost-effective energy conservation programs. o The Maryland PSC will determine transition costs or benefits as discussed further in this section. o The Maryland PSC is empowered to protect low-income customers through the establishment of a $34 million statewide universal service fund. 20 o Competitive billing is required to begin July 1, 2000 and competitive metering is required to begin in 2002. o A reciprocity provision is included for the sale of electricity, whereby utilities in neighboring states are prevented from competing with Maryland utilities unless the Maryland utility can compete in their service territory. o Customers who do not wish to change their electricity provider will receive "standard offer service" under procedures established by the Maryland PSC. The tax legislation made comprehensive changes to the state and local taxation of electric and gas utilities. Starting in the year 2000, the Maryland public service franchise tax will be altered to generally include a tax equal to .062 cents on each kilowatt-hour of electricity and .402 cents on each therm of natural gas delivered for final consumption in Maryland. The Maryland 2% franchise (gross receipts) tax on electric and natural gas utilities will continue to apply to transmission and distribution revenue. Additionally, all electric and natural gas utility results will become subject to the Maryland corporate income tax. Beginning July 1, 2000, the tax legislation also provides for a two-year phase-in of a 50% reduction in the local personal property taxes on machinery and equipment used to generate electricity for resale and a 60% corporate income tax credit for real property taxes paid on those facilities. The impact of these tax law changes will depend on the Maryland PSC's ruling on our transition plan and BGE's operating results once generation is deregulated. The changes are designed, in part, to tax Maryland electric generating facilities on a more comparable basis with electric generation in surrounding states. On June 29, 1999, BGE and a majority of active parties involved in the electric restructuring proceeding filed a proposed settlement agreement with the Maryland PSC. If approved by the Maryland PSC, the proposed settlement agreement would resolve the electric restructuring proceeding (transition costs, customer price protections, and unbundled rates for electric services) and the petition filed in September 1998 by the Office of People's Counsel (OPC) to lower our electric base rates. In addition, the proposed settlement agreement accelerates the timetable for customer choice and addresses certain other provisions of the Act discussed above. The electric restructuring proceeding and the petition filed by the OPC are discussed in BGE's 1998 Annual Report on Form 10-K. The major provisions of the proposed settlement agreement are: 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 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 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 of its potentially stranded investments 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. BGE had requested recovery of approximately $900 million, including costs associated with the transition to competition. 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 On July 1, 2000, 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 a nonregulated subsidiary of Constellation Energy. o BGE will reduce its generation assets by $150 million (pre-tax) during the period July 1, 1999 - June 30, 2000 in order to mitigate a portion of BGE's potentially stranded investments. o Universal service is provided for low-income customers without increasing their bills. BGE will provide its share of a statewide fund totaling $34 million. 21 The Maryland PSC held hearings beginning on August 11, 1999 that allowed BGE and other parties to provide testimony and comments about the proposed settlement agreement. We expect that the Maryland PSC will issue a final order by October 1, 1999. At June 30, 1999, we met the requirements to continue to apply Statement of Financial Accounting Standards (SFAS) No. 71, Accounting for the Effects of Certain Types of Regulation, to BGE's utility operations. When the Maryland PSC issues its final order, we believe that sufficient details of the transition plan will be known and the generation portion of BGE's electric business will no longer meet the provisions of SFAS No. 71. At that time, we would implement SFAS No. 101, "Regulated Enterprises - Accounting for the Discontinuation of FASB Statement No. 71." A provision under SFAS No. 101 requires an evaluation of potential impairments of plant assets under SFAS No. 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets To Be Disposed Of. If any of our generating plant assets are impaired under the provisions of SFAS No. 121, BGE would be required to record a write-down. The amount of any such write-down could materially affect BGE's financial position and results of operations. However, we cannot estimate the amount of the potential impairment loss, if any, at this time. Currently, Maryland law does not allow BGE to securitize the recovery of stranded investments. A securitization bill was introduced in the Maryland General Assembly this year but was not considered for enactment. It is expected that a securitization bill will be considered in the 2000 General Assembly. Securitization is a mechanism to recover stranded investments. Generally, bonds would be issued and the proceeds used primarily to reduce stranded investments and related capitalization of BGE. The bonds would be payable from irrevocable customer charges. Under the settlement agreement, BGE has agreed to apply 75% of any future savings associated with securitization to reduce the competitive transition charge paid by its customers. We cannot predict the ultimate effect the implementation of electric customer choice as described in this section will have on BGE's financial position or results of operations, but such effects could be material. Gas Business - ------------ 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 industrial and commercial gas customers, and 50,000 BGE residential gas customers (under a pilot program) have the option to purchase gas from other suppliers. On November 1, 1999, all BGE residential customers will have the same option. Utility Business Earnings per Share of Common Stock - --------------------------------------------------- Quarter Ended Six Months Ended June 30 June 30 --------------- ------------------ 1999 1998 1999 1998 -------- ------- -------- ------- Electric business... $ .37 $ .33 $ .67 $ .63 Gas business........ - .01 .15 .12 -------- ------- --------- -------- Total utility earnings per share $ .37 $ .34 $ .82 $ .75 ======== ======= ========= ======== Our utility earnings for the quarter ended June 30, 1999 increased $5.6 million, or $.03 per share compared to the same period of 1998. Our utility earnings for the six months ended June 30, 1999, increased $12.5 million, or $.07 per share compared to the same six months of 1998. We discuss the factors affecting utility earnings below. Electric Operations - ------------------- Electric Revenues - ----------------- The changes in electric revenues in 1999 compared to 1998 were caused by: Quarter Ended Six Months Ended June 30 June 30 1999 vs. 1998 1999 vs. 1998 --------------- ------------------ (In millions) Electric system sales volumes....... $ (1.1) $ 18.1 Base rates............ (0.5) (0.5) Fuel rates............ (0.8) 1.9 ------ ----- Total change in electric revenues from electric system sales........ (2.4) 19.5 Interchange and other sales......... 9.3 1.1 Other................. 0.9 1.1 -------- ------- Total change in electric revenues... $ 7.8 $ 21.7 ===== ====== 22 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 1999 compared to 1998 were: Quarter Ended Six Months Ended June 30 June 30 1999 vs. 1998 1999 vs. 1998 --------------- ----------------- Residential.......... 0.9% 4.8% Commercial........... 0.6 2.2 Industrial........... (8.8) (5.0) During the quarter ended June 30, 1999, we sold about the same amount of electricity to residential and commercial customers as we did during the same period of 1998. We sold less electricity to industrial customers mostly because usage by Bethlehem Steel (our largest customer) and other industrial customers decreased. Usage decreased at Bethlehem Steel as a result of a shut down for a planned upgrade to their facilities that temporarily reduced their electricity consumption. During the six months ended June 30, 1999, we sold more electricity to residential customers due to higher usage per customer, colder winter weather, and an increased number of customers. We would have sold even more electricity to residential customers except we had milder spring and summer weather. We sold more electricity to commercial customers mostly due to colder winter weather. We sold less electricity to industrial customers mostly because usage by Bethlehem Steel and other industrial customers decreased. Base Rates - ---------- During the quarter ended June 30, 1999, base rate revenues were about the same compared to the same period of 1998. During the six months ended June 30, 1999, base rate revenues were about the same compared to the same period of 1998. Although we sold more electricity in 1999, our base rate revenues were about the same because of lower conservation surcharge revenues. Fuel Rates - ---------- During the quarter ended June 30, 1999, fuel rate revenues were about the same compared to the same period of 1998. During the six months ended June 30, 1999, fuel rate revenues increased compared to the same period of 1998 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 a regional power pool with members that include many wholesale market participants, as well as BGE and seven 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 June 30, 1999, we had higher interchange and other sales compared to the same period of 1998 mostly because the milder spring and summer weather reduced the demand for system sales this quarter and increased the amount of energy we had available for off-system sales. In addition, we were able to sell energy off-system at a higher price. During the six months ended June 30, 1999, we had higher interchange and other sales compared to the same period of 1998 mostly because the price per megawatt of electricity we sold was higher due to market conditions. Electric Fuel and Purchased Energy Expenses - ------------------------------------------- Quarter Ended Six Months Ended June 30 June 30 ----------------- ------------------ 1999 1998 1999 1998 -------- ------- ------- -------- (In millions) Actual Costs......... $130.6 $124.1 $257.9 $238.7 Net recovery (deferral) of costs under electric fuel rate clause (see Note 1 of BGE's 1998 Form 10-K)......... (10.6) (8.5) (16.7) 3.4 ------ ----- ------ ----- Total electric fuel and purchased energy expenses........... $120.0 $115.6 $241.2 $242.1 ====== ====== ======= ======= Actual Costs - ------------ During the quarter and six months ended June 30, 1999, our actual costs of fuel to generate electricity (nuclear fuel, coal, gas, or oil) and electricity we bought from others was higher compared to the same periods of 1998 mostly because the price of electricity we bought from others was higher. The price of electricity changes based on market conditions, complex pricing formulas for PJM transactions, and contract terms. 23 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. During the quarter and six months ended June 30, 1999, our actual costs of fuel and energy were higher than the fuel rate revenues we collected from our customers. Gas Operations - -------------- Gas Revenues - ------------ The changes in gas revenues in 1999 compared to 1998 were caused by: Quarter Ended Six Months Ended June 30 June 30 1999 vs. 1998 1999 vs. 1998 --------------- ------------------ (In millions) Gas system sales volumes....... $ 0.6 $ 6.4 Base rates............ (0.3) 2.3 Weather normalization. (0.1) 3.6 Gas cost adjustments.. 5.0 12.8 ----- ------ Total change in gas revenues from gas system sales........ 5.2 25.1 Off-system sales...... (7.6) (15.1) Other................. 0.3 0.1 ------ ------- Total change in gas revenues........ $(2.1) $ 10.1 ====== ====== Gas System Sales Volumes - ------------------------ The percentage changes in our gas system sales volumes, by type of customer, in 1999 compared to 1998 were: Quarter Ended Six Months Ended June 30 June 30 1999 vs. 1998 1999 vs. 1998 --------------- ------------------ Residential........... 5.8% 10.3% Commercial............ 14.6 13.7 Industrial............ (12.9) (4.1) During the quarter ended June 30, 1999, we sold more gas to residential and commercial customers mostly because of two factors: colder weather and the number of customers increased. We would have sold even more gas to commercial customers except usage per customer decreased. We sold less gas to industrial customers mostly because usage by Bethlehem Steel and other industrial customers decreased. Usage by Bethlehem Steel decreased due to a shut down for a planned upgrade to their facilities. During the six months ended June 30, 1999, we sold more gas to residential customers mostly because of two factors: colder winter weather and the number of customers increased. We would have sold even more gas to residential customers except we had lower usage per customer. We sold more gas to commercial customers mostly because of colder winter weather, increased usage per customer, and an increased number of customers. We sold less gas to industrial customers mostly because usage by Bethlehem Steel and other industrial customers decreased. Base Rates - ---------- During the quarter ended June 30, 1999, base rate revenues were about the same compared to the same period of 1998. During the six months ended June 30, 1999, base rate revenues were higher than they were during the same period of 1998. Effective March 1, 1998, the Maryland PSC allowed us to increase our base rates which increased our base rate revenues over the twelve-month period March 1998 through February 1999 by approximately $16 million. Weather Normalization - --------------------- Effective March 1, 1998, the Maryland PSC allowed us to implement 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 will be based on weather that is considered "normal" for the month and, therefore, will not be 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 which include a market based rate incentive mechanism. These clauses operate similar to the electric fuel rate clause described in the "Electric Fuel Rate Clause" section above. 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 essentially the same as the base rate charged for gas sales and are included in gas system sales volumes. During the quarter and six months ended June 30, 1999, gas cost adjustment revenues increased compared to the same periods of 1998 mostly because we sold more gas at a higher price. 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). During the quarter and six months ended June 30, 1999, revenues from off-system gas sales decreased compared to the same periods of 1998 mostly because we sold less gas off-system. Gas Purchased For Resale Expenses - --------------------------------- Quarter Ended Six Months Ended June 30 June 30 ---------------- ------------------ 1999 1998 1999 1998 -------- ------- ------- -------- (In millions) Actual costs........ $ 29.8 $ 32.6 $123.0 $129.1 Net recovery (deferral) of costs under gas adjustment clauses 3.2 (0.4) 12.1 1.3 ------ ------ ------ ------- Total gas purchased for resale expenses.. $ 33.0 $ 32.2 $135.1 $130.4 ======== ======= ======= ======= 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 and six months ended June 30, 1999, actual gas costs decreased compared to the same period of 1998 mostly because we bought less 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 and six months ended June 30, 1999, our actual gas costs were lower than the fuel rate revenues we collected from our customers. Other Operating Expenses - ------------------------ Operations and Maintenance Expenses - ----------------------------------- During the quarter ended June 30, 1999, operations and maintenance expenses decreased $8.8 million compared to the same period of 1998 mostly because of two factors: o in 1998, we recorded a $6.0 million write-off of contributions to a third party for a low-level radiation waste facility that was never completed, and o the timing of costs associated with the annual refueling outage at Calvert Cliffs. During the six months ended June 30, 1999, operations and maintenance expenses increased $15.0 million compared to the same period of 1998 mostly because of higher benefit costs and costs related to a major winter storm during 1999. Depreciation and Amortization Expenses - -------------------------------------- During the quarter ended June 30, 1999, depreciation and amortization expenses were about the same compared to the same period of 1998. During the six months ended June 30, 1999, depreciation and amortization expenses decreased $5.0 million compared to the same period of 1998 mostly because 1998 expense reflects an adjustment for the reduction of the amortization period for certain computer software from five years to three years. We did not have a similar adjustment in 1999. Other Income and Expenses - ------------------------- Interest Expense - ---------------- During the quarter and six months ended June 30, 1999, interest expense was about the same compared to the same periods of 1998. 25 Income Taxes - ------------ During the quarter ended June 30, 1999, our total income taxes increased $4.5 million compared to the same period of 1998. During the six months ended June 30, 1999, our total income taxes increased $8.8 million compared to the same period of 1998. These increases occurred because we had higher taxable income from both our utility operations and our diversified businesses. Diversified Businesses - ---------------------- Our diversified businesses engage primarily in energy services. We list each of our diversified businesses in the "Introduction" section on page 17. We describe our diversified businesses in more detail in BGE's 1998 Annual Report on Form 10-K under "Item 1. Business -- Diversified Businesses." Constellation Enterprises and its subsidiaries were subsidiaries of BGE prior to April 30, 1999 and are included in the consolidated financial statements of BGE through that date. Diversified Business Earnings per Share of Common Stock - ------------------------------------------------------- Quarter Ended Six Months Ended June 30 June 30 --------------- ------------------ 1999 1998 1999 1998 -------- ------- ------- ------- Energy services Power marketing and trading.. $ .08 $ .01 $ .13 $ .01 Power projects. .04 .04 .11 .11 Other.......... - - - - -------- -------- -------- -------- Total energy services earnings per share.......... .12 .05 .24 .12 Other diversified businesses earnings per share.......... (.04) - (.05) .02 -------- -------- -------- -------- Total earnings per share... $ .08 $ .05 $ .19 $ .14 ======== ======== ======== ======== Our total diversified business earnings for the quarter ended June 30, 1999 increased $5.0 million, or $.03 per share, compared to the same period of 1998. Our total diversified business earnings for the six months ended June 30, 1999 increased $6.5 million, or $.05 per share, compared to the same period of 1998. We discuss the factors affecting the earnings of our diversified businesses below. Energy Services - --------------- Power Marketing and Trading - --------------------------- During the quarter and six months ended June 30, 1999, earnings from our power marketing and trading business increased compared to the same periods of 1998 mostly because of increased transaction margins and volume. Constellation Power Source uses the mark-to-market method of accounting for its trading activities. We discuss the mark-to-market method of accounting and Constellation Power Source's trading activities in more detail in BGE's 1998 Annual Report on Form 10-K. As a result of the nature of its trading 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 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 June 30, 1999 compared to December 31, 1998 because of greater business activity during the period. Power Projects - -------------- During the quarter and six months ended June 30, 1999, earnings from our power projects business were about the same compared to the same periods of 1998. 26 California Power Purchase Agreements - ------------------------------------ Constellation Power and subsidiaries and Constellation Investments have $304.3 million invested in 15 projects that sell electricity in California under power purchase agreements called "Interim Standard Offer No. 4" agreements. Earnings from these projects were $5.9 million, or $.04 per share, for the quarter ended June 30, 1999 compared to $7.4 million, or $.05 per share for the same period of 1998. Earnings from these projects were $13.9 million, or $.09 per share, for the six months ended June 30, 1999 compared to $17.4 million, or $.12 per share for the same period of 1998. 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. We describe these projects and the transition process in detail in the Notes to Consolidated Financial Statements on page 15. International - ------------- At June 30, 1999, Constellation Power had invested about $181.1 million in 11 power projects in Latin America compared to $102.7 million invested in Latin America at June 30, 1998. These investments include: o the purchase of a 51% interest in a Panamanian electric distribution company for approximately $90 million in 1998 by an investment group in which subsidiaries of Constellation Power hold an 80% interest, and o approximately $98 million for the purchase of existing electric generation facilities and the construction of an electric generation facility in Guatemala. In the future, Constellation Power expects to expand its power projects business further in both domestic and international projects. Other Energy Services - --------------------- During the quarter and six months ended June 30, 1999, earnings from our other energy services businesses were about the same compared to the same periods of 1998. Other Diversified Businesses - ---------------------------- During the quarter and six months ended June 30, 1999, earnings from our other diversified businesses were lower compared to the same periods of 1998 mostly because our financial investments business had lower earnings from its investment in Capital Re Corporation (Capital Re). In May 1999, our financial investments business announced that it will exchange its shares of common stock in Capital Re for common stock of ACE Limited (ACE) as part of a business combination whereby ACE will acquire all of the outstanding capital stock of Capital Re. In June 1999, our financial investments business wrote-down its $94.2 million investment in Capital Re stock by $3.6 million after-tax, or $.02 per share to reflect the valuation of this pending business combination. Upon closing, which is expected to occur in the fourth quarter of 1999, final valuation will occur, and further write-downs may be necessary. Based on the market value of ACE's common stock as of the date of this report, our financial investments business would have to write-down its investment by an additional $12 million after-tax, or $.08 per share. However, the exact amount of a write-down, if any, will depend on the market value of Ace's common stock at the time of closing. Earnings from our real estate and senior-living facilities business were about the same compared to the same periods of 1998. 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 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 diversified subsidiaries. Management's current real estate strategy is to hold each real estate project until we can realize a reasonable value for it. Management evaluates strategies for all its businesses, including real estate, on an ongoing basis. We anticipate that competing demands for our financial resources and changes in the utility industry will cause us to evaluate thoroughly all diversified business 27 strategies on a regular basis so we use capital and other resources in a manner that is most beneficial. 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 projects. If we were to decide to sell our real estate projects, we could have write-downs. In addition, if we were to sell our real estate 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. It may be helpful for you to understand when we are required, by accounting rules, to write down the value of a real estate project to market value. A write-down is required 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. In August 1999, our senior-living facilities business announced that it has entered into an agreement to sell all but one of its senior-living facilities to Sunrise Assisted Living, Inc. Under the terms of the agreement, Sunrise will acquire twelve of our existing senior-living facilities, three facilities under construction, and several sites under development for $72.2 million in cash and $16.0 million in debt assumption. The sale is scheduled to close in the third quarter of 1999, provided that certain conditions have been fulfilled. We expect the sale to result in a write-down of approximately $4.0 million after-tax, or $.03 per share. We discuss our real estate and senior-living facilities business further in the Notes to Consolidated Financial Statements on page 16. Financial Condition - ------------------- Cash Flows - ---------- For the six months ended June 30, 1999 1998 - ------------------------------------------------------- (In millions) Cash provided by (used in): Operating Activities $ 370.2 $ 403.4 Investing Activities (195.5) (249.3) Financing Activities (245.0) (14.2) During the six months ended June 30, 1999, we generated less cash from operations compared to the same period in 1998 mostly because of changes in working capital requirements. We would have generated even less cash from operations except we had improved operating results. During the six months ended June 30, 1999, we used less cash for investing activities compared to the same period in 1998 mostly because our power projects business invested in the purchase of a generation facility in Guatemala in 1998. We did not have a similar investment in 1999. During the six months ended June 30, 1999, we used more cash for financing activities compared to the same period of 1998 mostly because we repaid more, and issued less, long-term debt. We would have used more cash for financing activities except our net short-term borrowings were higher during the first six months of 1999. 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 28 Capital Resources - ----------------- Our business requires a great deal of capital. Our actual consolidated capital requirements for the six months ended June 30, 1999, along with estimated annual amounts for the years 1999 through 2001, are shown below. For the twelve months ended June 30, 1999, the ratio of earnings to fixed charges for Constellation Energy was 2.75. The ratio of earnings to fixed charges for BGE was 3.46 and the ratio of earnings to combined fixed charges and preferred and preference dividend requirements for BGE was 3.08. Investment requirements for 1999 through 2001 include estimates of funding for existing and anticipated projects. We continuously review and modify those estimates. Actual investment requirements may vary from the estimates included in the table below because of a number of factors including: o regulation, legislation, and competition, o load growth, 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 "Forward Looking Statements" on page 38.
Six Months Ended June 30, Calendar Year Estimates 1999 1999 2000 2001 --------- ------- -------- -------- (In millions) Utility Business Capital Requirements: - -------------------------------------- Construction expenditures (excluding AFC) Electric $121 $ 285 $321 $278 Gas 27 74 73 69 Common 13 25 22 18 -------- ------- ------- ------- Total construction expenditures 161 384 416 365 AFC 6 12 13 19 Nuclear fuel (uranium purchases and processing charges) 18 48 50 48 Deferred energy conservation expenditures - 1 - - Retirement of long-term debt and redemption of preference stock 212 341 253 282 -------- ------- ------- ------- Total utility business capital requirements 397 786 732 714 -------- ------- ------- ------- Diversified Business Capital Requirements: - ------------------------------------------ Investment requirements 33 402 498 556 Retirement of long-term debt 113 201 273 367 -------- ------- ------- ------- Total diversified business capital requirements 146 603 771 923 -------- ------- ------- ------- Total capital requirements $543 $1,389 $1,503 $1,637 ======== ======= ======= =======
Capital Requirements of Our Utility Business - -------------------------------------------- Our estimates of future electric construction expenditures do not include costs to build more generating units. Electric construction expenditures include improvements to generating plants and to our transmission and distribution facilities. Future electric construction expenditures include estimated costs for replacing the steam generators and renewing the operating licenses at Calvert Cliffs. The operating licenses expire in 2014 for Unit 1 and in 2016 for Unit 2. We estimate these Calvert Cliffs costs to be: o $34 million in 1999, o $44 million in 2000, and o $63 million in 2001. We estimate that during the two-year period 2002 through 2003, we will spend an additional $151 million to complete the replacement of the steam generators and extend the operating licenses at Calvert Cliffs. We discuss the license extension process further in the "Other Matters - Calvert Cliffs License Extension" section of BGE's 1998 Annual Report on Form 10-K. 29 If we do not replace the steam generators, we estimate that Calvert Cliffs could not operate for the full term of its current operating licenses. We expect the steam generator replacements to occur during the 2002 refueling outage for Unit 1 and during the 2003 outage for Unit 2. Additionally, our estimates of future electric 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 $34 million in 1999, o $61 million in 2000, and o $18 million in 2001. We discuss the NOx regulations in the "Environmental Matters" section of the Notes to Consolidated Financial Statements on page 13. During the twelve months ended June 30, 1999, our utility operations provided about 100% of the cash needed to meet its capital requirements, excluding cash needed to retire debt and redeem preference stock. 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. During the three years from 1999 through 2001, we expect utility operations to provide about 115% of the cash needed to meet its capital requirements, excluding cash needed to retire debt and redeem preference stock. When BGE cannot meet utility capital requirements internally, BGE sells 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, the retirement of debt, redemption of preference stock, and payments of interest and dividends 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 June 30, 1999 the Federal Energy Regulatory Commission has authorized BGE to issue up to $700 million of short-term borrowings, including commercial paper. To support its commercial paper program, BGE maintains $83 million in committed bank lines of credit and has $100 million in bank revolving credit agreements. Capital Requirements of Our Diversified Businesses - -------------------------------------------------- We expect to expand certain of our energy services businesses. This will require additional funding for: o growing our power marketing and trading business, o the development and acquisition of power projects, as well as loans made to project entities, o investments in financial limited partnerships, and o funding for construction of cooling system projects. The investment requirements exclude Constellation Power Source, Inc.'s commitment to contribute up to $175 million in equity to fund its investment in Orion Power Holdings, Inc. Orion acquires electric generating plants in the United States and Canada. To date, Constellation Power Source has funded $101 million of this commitment. Our diversified businesses have met their capital requirements in the past through borrowing, cash from their operations, sales of receivables, and from time to time, equity contributions from BGE. Future funding for the expansion of our energy services businesses is expected from internally generated funds, short-and long-term financing by Constellation Energy, including newly established commercial paper and medium-term note programs, and from time to time equity contributions from Constellation Energy. BGE Home Products & Services may also meet capital requirements through sales of receivables. At June 30, 1999, Constellation Energy has a commercial paper program where it can issue up to $500 million in short-term notes to fund its diversified businesses. To support its commercial paper program, Constellation Energy maintains a $25 million committed bank line of credit and has a $135 million revolving credit agreement, under which it can also issue letters of credit. Our diversified businesses also have revolving credit agreements totaling $135 million to provide additional liquidity for short-term financial needs. If we can get a reasonable value for our real estate projects, 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. 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 BGE's 1998 Annual Report on Form 10-K under "Item 1. Business - Environmental Matters." These details include financial information. Some of the information is about costs that may be material. Year 2000 Readiness Disclosure - ------------------------------ We have not experienced any significant year 2000 problems to date and we do not expect any significant problems to impair our operations as we transition to the new century. However, due to the magnitude and complexity of the year 2000 issue, even the most conscientious efforts cannot guarantee that every problem will be found and corrected prior to January 1, 2000. We believe that all of BGE's "mission critical" systems for electric and gas production and delivery are year 2000 ready. Mission critical systems include BGE's: o electric generating plants, including Calvert Cliffs Nuclear Power Plant, o energy distribution systems, o natural gas delivery system, and o mission critical applications supporting these systems. Please refer to "Forward Looking Statements" on page 38. Utility Business - ---------------- We established a year 2000 Program Management Office (PMO). Based on a work plan developed by the PMO, we have targeted the following six key areas: o digital systems (devices with embedded microprocessors such as power instrumentation, controls, and meters), o telecommunications systems, o major suppliers, o information technology applications (our customer, business, and human resources information systems), o computer hardware and software infrastructure, and o contingency plans. Of these areas, digital systems have the most impact on our ability to provide electric and gas service. Telecommunications, major suppliers, and certain information technology applications also impact our ability to provide electric and gas service. Year 2000 Project Phases - ------------------------ Our year 2000 project is divided into two phases: o Phase I - initial assessment and detailed analysis, and o Phase II - testing, remediation, certification, and contingency planning. Phase I involves conducting an inventory of all systems and identifying appropriate resources. We have identified the following appropriate resources for each system or piece of equipment: o BGE employees familiar with each system or piece of equipment, o specialized contractors, and o specific vendors. Phase I also includes developing action plans to ensure that the key areas identified above are year 2000 ready. The action plans for each system or piece of equipment include: o our budget, o schedules for Phase I and II, and o our remediation approach - repair, upgrade, replace or retire. 31 In evaluating our risks and estimating our costs, we utilized employees with expertise in each line of business to perform the activities under Phase I. We believe our employees are the most familiar with their systems or equipment and therefore will provide a reliable estimate of our risks and costs. Phase II includes converting and testing all of our systems. Each system will be tested by those employees used in Phase I following formal guidelines developed by the PMO. Each system or piece of equipment will then be certified by a tester and the PMO, following testing guidelines developed with the help of outside consultants. We plan to have an independent readiness review of all our systems and may have some of our systems' year 2000 testing independently certified. Phase II also includes identifying our major suppliers and developing contingency plans. We have identified our major suppliers and have assessed their year 2000 readiness through surveys and interviews. We believe that our mission critical suppliers (for example, coal suppliers and natural gas pipeline suppliers) are year 2000 ready. We are still evaluating the readiness of our other major suppliers through interviews. Contingency Planning - -------------------- Year 2000 operational contingency plans have been developed utilizing employees familiar with the operations in each area of our business. The individual plans are integrated into a corporate-wide Year 2000 Contingency Plan. Associated staffing plans have been completed identifying all essential personnel needed on-site for the rollover weekend (December 31, 1999 - January 1, 2000) to deal with any problems, if they should occur. BGE will have a corporate command center staffed during the rollover weekend to serve as the communication hub for year 2000 status information for BGE and all diversified businesses. The center will have two-way communications with the electric, gas, retail services, nuclear, and information technology operations command centers for the purpose of collecting information and coordinating responses. The center will also have two-way communications with the Maryland Emergency Management Agency and local emergency operation centers in BGE's service territory. Detailed coordination of the plans will continue, and personnel will be trained in order to provide for a smooth transition. The year 2000 contingency plans were developed using the contingency guidelines issued by the Nuclear Energy Institute (which are endorsed by the Nuclear Regulatory Commission), the contingency guidelines issued by the North American Electric Reliability Council (NERC), and guidance from consultants. We are also addressing the impact of electric power grid problems that may occur outside of our own electric system. We developed year 2000 electric power grid impact contingency plans through our various electric interconnection affiliations and continue to refine them. The PJM interconnection has drafted year 2000 operational preparedness plans and restoration scenarios and will continue to coordinate and develop these plans during the third quarter of 1999 in cooperation with NERC. The NERC will continue to perform monthly assessments of electric utility industry to communicate the readiness of the national electric grid for year 2000. On April 9, 1999, we participated in a NERC sponsored drill, along with other North American electric bulk operating utilities. The drill focused on testing backup voice and data communications and protocols. The drill was successful as it demonstrated our ability to operate the bulk power and gas distribution systems reliably during a partial loss of telephone communications. The NERC has scheduled a second drill beginning September 8, 1999 to simulate January 1, 2000. On June 2, 1999, we conducted a successful test on our energy control system and its interface with the PJM. This system monitors and controls the flow of electricity on BGE's electric grid. Through the Electric Power Research Institute (EPRI), an industry-wide effort has been established to deal with year 2000 problems affecting digital systems and equipment used by the nation's electric power companies. Under this effort, participating utilities continue to assess specific vendors' system problems and test plans. These assessments are being shared by the industry as a whole to facilitate year 2000 problem solving. BGE has joined the American Gas Association (AGA) in an initiative similar to the one with NERC to facilitate year 2000 problem solving among gas utilities. The AGA and its affiliates perform quarterly assessments of the gas utility industry to communicate the readiness of its members for the year 2000. Current Status - -------------- The most reasonably likely worst case scenario faced by our utility business is a localized interruption in providing electric and gas service to our customers. We cannot predict the impact of any interruption on our results of operations, but the impact could be material. For all systems and equipment, both mission critical and non-mission critical, we have completed Phase I. We have completed Phase II for all our mission critical 32 systems. The chart below indicates our progress for completion of year 2000 readiness for our non-mission critical systems as of the date of this report. The few remaining non-mission critical systems are year 2000 tested and require production work during July and August. Our non-mission critical systems are expected to be year 2000 ready by September 1999. Phase I Phase II ------- -------- (approximate % complete) Digital systems 100% 99% Telecommunications systems 100% 99% Major suppliers 100% 97% Information technology applications 100% 97% Computer hardware and software infrastructure 100% 99% The completion percentages listed above are reviewed by our PMO in monthly status meetings with the personnel responsible for each project and their supervision. Monthly progress is also monitored by senior Constellation Energy and BGE management. Costs - ----- In the following table, we show the breakdown of our total costs between normal system replacements that will be capitalized (included in the Consolidated Balance Sheets) and the costs that will be expensed (included in our Consolidated Statements of Income) through operations and maintenance (O&M) cost. We also show the breakdown of non-incremental (previously included in our information technology budget) and incremental O&M cost: Estimated Total Actual Costs Costs Costs ------------ ----- ----- Through 1996 - June 30, Remainder 1997 1998 1999 of 1999 2000 ---- ---- ---- ------- ---- (In millions) Total Cost $1.8 $18.9 $8.9 $12.6 $3.8 $46.0 Less: Capital Cost - 7.3 2.4 4.7 0.1 14.5 ------ ----- ------ ------- ------ ------ O&M cost 1.8 11.6 6.5 7.9 3.7 31.5 Less: non-incremental O&M cost 1.8 4.6 3.1 3.6 1.8 14.9 ------ ----- ------ ------- ------ ------ Incremental O&M cost $- $7.0 $3.4 $4.3 $1.9 $16.6 ====== ==== ===== ====== ====== ====== The costs incurred in 1996 and 1997 were for Phase I. The costs incurred in 1998 were for Phases I and II. Cost incurred in 1999 and 2000 will be for Phase II. In 1998, we had the equivalent of approximately 110 full-time employees assigned to our year 2000 project. We expect a similar level of commitment of resources to continue during 1999. Diversified Businesses - ---------------------- Overview - -------- Our diversified businesses have established year 2000 task forces to address their year 2000 issues. As the initial assessments are completed, the businesses have developed, and will be developing, action plans to prepare their systems for the year 2000. Outside consultants have been retained by several of our diversified businesses to help complete the initial assessment and detailed analysis phase, and to assist in the testing, remediation, and certification phase of their year 2000 projects. The action plans developed are similar to those used by our utility business, including a test certification process. All systems are expected to be certified by December 1999. Our diversified businesses are evaluating whether they will have their year 2000 testing independently certified. In evaluating their risks and estimating their costs, our diversified businesses utilized employees with expertise in each line of business to perform initial assessments. We believe our diversified businesses' employees are the most familiar with their systems or equipment and therefore will provide a reliable estimate of our risks and costs. The progress of our diversified businesses' year 2000 projects are reviewed by their year 2000 task forces in monthly status meetings with the personnel responsible for each project and their supervision. Monthly progress is also monitored by senior management for each business and monthly updates are provided to Constellation Energy senior management. Contingency Planning - -------------------- Each of our diversified businesses will develop contingency plans, which are expected to be completed by December 1999. Current Status - -------------- The most reasonably likely worst case scenarios faced by our energy services businesses and our other diversified businesses are discussed below. However, if any of these scenarios actually occurred, the impact is 33 not expected to be material to our consolidated financial results. Energy Services - --------------- The most reasonably likely worst case scenarios for any one of our power projects would be: o a shutdown of the plant's systems (most of which can be manually overridden), o inability of the purchasing utility to take the plant's power, or o failure of critical suppliers. Personnel at each plant have substantially completed their assessment of their particular year 2000 issues and have substantially completed the testing, remediation, and certification phase of their year 2000 project. In Latin America, personnel are focused on assessing the year 2000 readiness of suppliers and are preparing contingency plans where necessary. For our power marketing and trading business and our energy products and services business, the most reasonably likely worst case scenario would be encountering any Internet access problems with trading partners, transmission service providers, independent system operators, power exchanges, or various electronic bulletin boards. Each of these businesses has three Internet service providers for alternate routing to critical Internet sites necessary to perform day-to-day business functions. Both have completed the assessment and detailed analysis phase and have substantially completed the testing, remediation, and certification phase of its year 2000 project. For our home products and commercial building systems business, the most reasonably likely worst case scenarios would be any interruption in billing customers or renewing maintenance contracts. This business completed the assessment and detailed analysis phase and has substantially completed the testing, remediation, and certification phase of its year 2000 project. Other Diversified Businesses - ---------------------------- The most reasonably likely worst case scenarios for our financial investments business would be a breakdown in the systems of the brokers or safekeeping banks which it uses to trade, or the failure of its investment managers' computer programs that set investment strategy. This business is monitoring the year 2000 readiness of its banks, brokers, and investment managers. For our real estate and senior-living facilities business, the most reasonably likely worst case scenario is a failure of the systems that support the health, safety, and welfare of residents in the senior-living facilities. Personnel at each senior-living facility are involved in assessing its particular year 2000 issues and have a consultant coordinating the overall year 2000 activity. Costs - ----- We estimate our total year 2000 costs for our power projects business to be approximately $4.2 million, of which $1.2 million is related to our year 2000 efforts for our Panamanian electric distribution company. The total estimated year 2000 costs for our remaining diversified businesses are approximately $2.8 million. Accounting Standards Issued - --------------------------- In July 1999, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards (SFAS) No. 137 regarding the delay of the effective date for SFAS No. 133 on derivatives and hedging. This standard delays the effective date by one year and therefore, we must adopt the provisions of SFAS No. 133 in our financial statements for the quarter ended March 31, 2001. Item 3. Quantitative and Qualitative Disclosures About Market Risk - ------------------------------------------------------------------ We discuss the following information related to our market risk: o quarterly financing activities in the Notes to Consolidated Financial Statements on page 12, and o trading activities of our power marketing and trading business in the "Power Marketing and Trading" section of Management's Discussion and Analysis on page 26. 34 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 520 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, eight of these cases were settled before trial for amounts that were immaterial. 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 70 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. Item 2. Changes in Securities and Use of Proceeds - ------- ----------------------------------------- Effective April 30, 1999, the outstanding common stock of BGE automatically became shares of common stock of Constellation Energy. Certain rights of the holders of common stock of Constellation Energy were modified. We discussed this further in the joint proxy statement / prospectus of Constellation Energy and BGE in Post-Effective Amendment No. 1 to Form S-4 (Registration No. 33-64799), under the section "Comparative Shareholder Rights," included as an exhibit in our March 31, 1999 Form 10-Q. 35 PART II. OTHER INFORMATION (Continued) On July 16, 1999, by resolution of the Board of Directors, the Company elected to become subject to Sections 3-803 and 3-805 of the Maryland General Corporation Law (MGCL). Section 3-803 provides for a classified board of directors of three classes each having a three-year term. o Class I Directors shall initially be Douglas L. Becker, J. Owen Cole, Dan A. Colussy, Edward A. Crooke, George V. McGowan and Michael D. Sullivan and shall have an initial term continuing until the annual meeting of stockholders in 2000 and until their successors are elected and qualify; o Class II Directors shall initially be H. Furlong Baldwin, James T. Brady, Beverly B. Byron, James R. Curtiss, Esquire, Jerome W. Geckle and George L. Russell, Jr., Esquire and shall have an initial term continuing until the annual meeting of stockholders in 2001 and until their successors are elected and qualify; and o Class III Directors shall initially be Roger W. Gale, Dr. Freeman A. Hrabowski, III, Nancy Lampton, Charles R. Larson, Christian H. Poindexter and Mayo A. Shattuck, III and shall have an initial term continuing until the annual meeting of stockholders in 2002 and until their successors are elected and qualify. Section 3-805 provides that the Secretary of the Corporation may call a special meeting of the holders of common stock only o on the written request of the stockholders entitled to cast at least a majority of all votes entitled to be cast at the meeting; and o in accordance with the procedures set forth under Section 2-502(b)(2) and (3) and (e) of the MGCL. If there is any inconsistency with any provisions of the Charter or By-laws of the Company, these MGCL provisions will govern. Also, on July 16, 1999 by resolution of the Board of Directors, the Company elected to amend its By-laws to provide that the Company is not subject to Subtitle 7 of Title 3 of the MGCL, reserving the ability to repeal the election. Subtitle 7 provides that control shares of a Maryland corporation acquired in a control share acquisition have no voting rights except to the extent approved by a vote of two-thirds of the votes entitled to be cast on the matter. The statute defines key terms such as control shares and control share acquisition and requires a specific process by which the shareholder meeting would be convened. 36 PART II. OTHER INFORMATION (Continued) Item 4. Submission of Matters to a Vote of Security Holders - ------- --------------------------------------------------- On April 16, 1999, BGE held its annual meeting of shareholders. At that meeting, the following matters were voted upon: 1. The proposal to approve a one-for-one share exchange and formation of the holding company, Constellation Energy Group, Inc., was approved. With respect to holders of common stock, the number of affirmative votes cast were 105,331,130, the number of negative votes cast were 5,470,076, and the number of abstentions were 1,696,026. 2. All of the Directors nominated by BGE were selected as follows: COMMON SHARES CAST: ------------------- For Against Abstain --- ------- ------- H. Furlong Baldwin 122,377,056 669,820 3,938,282 Douglas L. Becker 122,309,079 737,996 3,938,282 Beverly B. Byron 122,169,356 878,037 3,938,282 J. Owen Cole 122,469,876 577,517 3,938,282 Dan A. Colussy 122,449,628 597,248 3,938,282 Edward A. Crooke 122,326,040 721,036 3,938,282 James R. Curtiss 121,743,032 1,304,361 3,938,282 Jerome W. Geckle 122,428,200 619,193 3,938,282 Freeman A. Hrabowski, III 122,316,201 730,874 3,938,282 Nancy Lampton 122,611,592 435,484 3,938,282 Adm. Charles R. Larson 122,309,752 737,641 3,938,282 George V. McGowan 122,300,343 747,050 3,938,282 Christian H. Poindexter 121,692,510 1,354,565 3,938,282 George L. Russell, Jr. 121,533,422 1,513,654 3,938,282 Michael D. Sullivan 122,154,708 892,685 3,938,282 3. The ratification of PricewaterhouseCoopers LLP as independent accountants was approved. With respect to holders of common stock, the number of affirmative votes cast were 125,314,110, the number of negative votes cast were 833,642, and the number of abstentions were 1,050,085. 4. The proposal to close and decommission the Calvert Cliffs Nuclear Plant before or on the originally planned date was defeated. With respect to holders of common stock, the number of affirmative votes cast were 4,772,902, the number of negative votes cast were 103,507,020, and the number of abstentions were 4,223,817. 5. The proposal for the adoption and implementation of a policy of Confidential Voting was defeated. With respect to holders of common stock, the number of affirmative votes cast were 44,344,736, the number of negative votes cast were 64,275,026, and the number of abstentions were 3,889,606. 37 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 final terms of proposed settlement agreement filed with the Maryland PSC (including rate reduction and recovery of stranded investments), o commodity price risk, and o year 2000 readiness. 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. 3(a) Constellation Energy Group, Inc. Articles Supplementary, dated July 19, 1999 (Designated as Exhibit 99.1 in Form 8-K dated July 16, 1999.) Exhibit No. 3(b) By-Laws of Constellation Energy Group, Inc., amended as of July 16, 1999 (Designated as Exhibit 99.2 in Form 8-K dated July 16, 1999.) 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.
(b) Reports on Form 8-K for the quarter ended June 30, 1999: Date Filed Items Reported ---------- -------------- April 30, 1999 Item 5. Other Events Item 7. Financial Statements and Exhibits June 16, 1999 Item 5. Other Events June 29, 1999 Item 5. Other Events Item 7. Financial Statements and Exhibits 38 SIGNATURE --------------------------- Pursuant to the requirements of the Securities Exchange Act of 1934, each registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. CONSTELLATION ENERGY GROUP, INC. ----------------------------------- (Registrant) BALTIMORE GAS AND ELECTRIC COMPANY ----------------------------------- (Registrant) Date: August 13, 1999 /s/ D. A. Brune ----------------- ----------------------------------- D. A. Brune, Vice President on behalf of each Registrant and as Principal Financial Officer of each Registrant 39 EXHIBIT INDEX Exhibit Number ------ 3(a) Constellation Energy Group, Inc. Articles Supplementary, dated July 19, 1999 (Designated as Exhibit 99.1 in Form 8-K dated July 16, 1999.) 3(b) By-Laws of Constellation Energy Group, Inc., amended as of July 16, 1999 (Designated as Exhibit 99.2 in Form 8-K dated July 16, 1999.) 12(a) Constellation Energy Group, Inc. Computation of Ratio of Earnings to Fixed Charges. 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. 27(a) Constellation Energy Group, Inc. Financial Data Schedule. 27(b) Baltimore Gas and Electric Company Financial Data Schedule. EX-12 2 EXHIBIT 12(A) CONSTELLATION ENERGY GROUP, INC. AND SUBSIDIARIES COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES
12 Months Ended ------------------------------------------------------------------------------------- June December December December December December 1999 1998 1997 1996 1995 1994 ------------ ------------- ------------ ------------ ------------ ----------- (In Millions of Dollars) Net Income $ 324.9 $ 305.9 $ 254.1 $ 272.3 $ 297.4 $ 283.7 Taxes on Income, Including Tax Effect for BGE Preference Stock Dividends 181.1 169.3 145.1 148.3 152.0 137.6 ----------- ------------- ------------ ------------ ------------ ----------- Adjusted Net Income $ 506.0 $ 475.2 $ 399.2 $ 420.6 $ 449.4 $ 421.3 --------- ------------- ------------ ------------ ------------ ------------ Fixed Charges: Interest and Amortization of Debt Discount and Expense and Premium on all Indebtedness $ 257.7 $ 255.3 $ 234.2 $ 203.9 $ 206.7 $ 204.2 Earnings required for BGE Preference Stock Dividends 26.2 33.8 45.1 59.4 61.0 59.0 Capitalized Interest 2.3 3.6 8.4 15.7 15.0 12.4 Interest Factor in Rentals 1.8 1.9 1.9 1.5 2.1 2.0 ------------ ------------- ------------ ------------ ------------ ---------- Total Fixed Charges $ 288.0 $ 294.6 $ 289.6 $ 280.5 $ 284.8 $ 277.6 ------------ ------------- ------------ ------------ ------------ ---------- Earnings (1) $ 791.7 $ 766.2 $ 680.4 $ 685.4 $ 719.2 $ 686.5 ============ ============= ============ ============ ============ ========== Ratio of Earnings to Fixed Charges 2.75 2.60 2.35 2.44 2.52 2.47
(1) Earnings are deemed to consist of net income 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 ----------------------------------------------------------------------------------------- June December December December December December 1999 1998 1997 1996 1995 1994 ------------ ------------- ------------ ------------ ------------ ------------ (In Millions of Dollars) Net Income $ 331.8 $ 327.7 $ 282.8 $ 310.8 $ 338.0 $ 323.6 Taxes on Income 183.7 181.3 161.5 169.2 172.4 156.7 ------------ ------------- ------------ ------------ ------------ ------------ Adjusted Net Income $ 515.5 $ 509.0 $ 444.3 $ 480.0 $ 510.4 $ 480.3 ------------ ------------- ------------ ------------ ------------ ------------ Fixed Charges: Interest and Amortization of Debt Discount and Expense and Premium on all Indebtedness $ 205.4 $ 255.3 $ 234.2 $ 203.9 $ 206.7 $ 204.2 Capitalized Interest 2.0 3.6 8.4 15.7 15.0 12.4 Interest Factor in Rentals 1.0 1.9 1.9 1.5 2.1 2.0 ------------ ------------- ------------ ------------ ------------ ------------ Total Fixed Charges $ 208.4 $ 260.8 $ 244.5 $ 221.1 $ 223.8 $ 218.6 ------------ ------------- ------------ ------------ ------------ ------------ Preferred and Preference Dividend Requirements: (1) Preferred and Preference Dividends$ 17.1 $ 21.8 $ 28.7 $ 38.5 $ 40.6 $ 39.9 Income Tax Required 9.1 12.0 16.4 20.9 20.4 19.1 ------------ ------------- ------------ ------------ ------------ ------------ Total Preferred and Preference Dividend Requirements $ 26.2 $ 33.8 $ 45.1 $ 59.4 $ 61.0 $ 59.0 ------------ ------------- ------------ ------------ ------------ ------------ Total Fixed Charges and Preferred and Preference Dividend Requirements $ 234.6 $ 294.6 $ 289.6 $ 280.5 $ 284.8 $ 277.6 ============ ============= ============ ============ ============ ============ Earnings (2) $ 721.9 $ 766.2 $ 680.4 $ 685.4 $ 719.2 $ 686.5 ============ ============= ============ ============ ============ ============ Ratio of Earnings to Fixed Charges 3.46 2.94 2.78 3.10 3.21 3.14 Ratio of Earnings to Combined Fixed Charges and Preferred and Preference Dividend Requirements 3.08 2.60 2.35 2.44 2.52 2.47
(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 net income that includes earnings of BGE's consolidated subsidiaries, equity in the net income of BGE's unconsolidated subsidiary, income taxes (including deferred income taxes and investment tax credit adjustments), and fixed charges other than capitalized interest. EX-27 4 EXHIBIT 27(A) WARNING: THE EDGAR SYSTEM ENCOUNTERED ERROR(S) WHILE PROCESSING THIS SCHEDULE.
UT THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM CONSTELLATION ENERGY'S JUNE 30, 1999 INTERIM CONSOLIDATED INCOME STATEMENT, BALANCE SHEET AND STATEMENT OF CASH FLOWS AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH STATEMENTS. 1,000,000 6-MOS DEC-31-1999 JAN-01-1999 JUN-30-1999 PER-BOOK 5,645 1,719 1,292 578 0 9,234 1,494 0 1,516 3,004 0 190 2,964 0 0 109 467 7 0 0 2,493 9,234 1,752 89 1,390 1,479 273 4 277 126 151 0 151 126 113 370 1.01 1.01
EX-27 5 EXHIBIT 27(B)
UT THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM BALTIMORE GAS AND ELECTRIC COMPANY'S JUNE 30, 1999 INTERIM CONSOLIDATED INCOME STATEMENT, BALANCE SHEET AND STATEMENT OF CASH FLOWS AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH STATEMENTS. 1,000,000 6-MOS DEC-31-1999 JAN-01-1999 JUN-30-1999 PER-BOOK 5,645 387 564 569 0 7,165 1,494 0 880 2,374 0 190 2,511 0 0 109 190 7 0 0 1,784 7,165 1,602 83 1,262 1,345 257 3 260 112 148 7 141 126 87 414 0 0
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