UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
----------------------------------
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For The Quarterly Period Ended September 30, 1999
Commission file Exact name of registrant IRS Employer
number as specified in its charter Identification No.
------ --------------------------- ------------------
1-12869 CONSTELLATION ENERGY GROUP, INC. 52-1964611
1-1910 BALTIMORE GAS AND ELECTRIC COMPANY 52-0280210
Maryland
-----------------------------------
(State of Incorporation)
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 October 31, 1999.
1
Table of Contents
Part I. Financial Information Page
Item 1. Financial Statements
Constellation Energy Group, Inc. and Subsidiaries
Consolidated Statements of Income...................................................... 3
Consolidated Statements of Comprehensive Income........................................ 3
Consolidated Balance Sheets............................................................ 4
Consolidated Statements of Cash Flows.................................................. 6
Baltimore Gas and Electric Company and Subsidiaries
Consolidated Statements of Income...................................................... 7
Consolidated Statements of Comprehensive Income........................................ 7
Consolidated Balance Sheets............................................................ 8
Consolidated Statements of Cash Flows.................................................. 10
Notes to Consolidated Financial Statements.................................................. 11
Item 2. Management's Discussion and Analysis of Financial Condition
and Results of Operations
Introduction........................................................................... 16
Deregulation and Strategy.............................................................. 16
Results of Operations.................................................................. 17
Financial Condition.................................................................... 29
Capital Resources...................................................................... 29
Other Matters.......................................................................... 32
Item 3. Quantitative and Qualitative Disclosures About Market Risk.................................. 36
Part II. Other Information
Item 1. Legal Proceedings........................................................................... 37
Item 5. Other Information........................................................................... 38
Item 6. Exhibits and Reports on Form 8-K............................................................ 38
Signature............................................................................................ 39
Exhibit Index........................................................................................ 40
Constellation Energy Group, Inc. and Subsidiaries Computation of Ratio of Earnings to Fixed Charges.. 41
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................................................................. 42
2
CONSTELLATION ENERGY GROUP, INC. AND SUBSIDIARIES
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
Consolidated Statements of Income (Unaudited)
Three Months Ended Nine Months Ended
September 30, September 30,
1999 1998 1999 1998
---------- ---------- ----------- ----------
(In Millions, Except Per-Share Amounts)
Revenues
Electric $ 691.2 $ 722.5 $ 1,737.2 $ 1,746.8
Gas 60.1 62.1 332.7 324.7
Diversified businesses 219.1 149.4 652.7 496.2
---------- ---------- ----------- ----------
Total revenues 970.4 934.0 2,722.6 2,567.7
Expenses Other Than Fixed Charges and Income Taxes
Electric fuel and purchased energy 115.8 149.4 356.9 391.5
Gas purchased for resale 21.3 21.6 156.4 152.0
Operations 127.1 129.4 397.5 395.3
Maintenance 40.9 38.7 143.4 130.8
Diversified businesses - selling, general, and administrative 229.6 122.9 577.6 393.8
Depreciation and amortization 92.9 89.6 274.0 275.6
Taxes other than income taxes 65.1 62.0 177.2 168.6
---------- ---------- ----------- ----------
Total expenses other than fixed charges and income taxes 692.7 613.6 2,083.0 1,907.6
---------- ---------- ----------- ----------
Income From Operations 277.7 320.4 639.6 660.1
Other Income 1.2 3.5 5.7 6.2
---------- ---------- ----------- ----------
Income Before Fixed Charges and Income Taxes 278.9 323.9 645.3 666.3
Fixed Charges
Interest expense (net) 61.7 62.4 181.1 180.9
BGE preference stock dividends 3.4 6.8 10.2 18.3
---------- ---------- ----------- ----------
Total fixed charges 65.1 69.2 191.3 199.2
---------- ---------- ----------- ----------
Income Before Income Taxes 213.8 254.7 454.0 467.1
Income Taxes
Current 76.7 72.4 152.6 160.5
Deferred 3.2 23.2 20.9 19.4
Investment tax credit adjustments (2.2) (1.8) (6.4) (5.5)
---------- ---------- ----------- ----------
Total income taxes 77.7 93.8 167.1 174.4
---------- ---------- ----------- ----------
Net Income $ 136.1 $ 160.9 $ 286.9 $ 292.7
========== ========== =========== ==========
Earnings Applicable to Common Stock $ 136.1 $ 160.9 $ 286.9 $ 292.7
========== ========== =========== ==========
Average Shares of Common Stock Outstanding 149.6 148.7 149.6 148.3
Earnings Per Common Share and
Earnings Per Common Share - Assuming Dilution $0.91 $1.08 $1.92 $1.97
Dividends Declared Per Common Share $0.42 $0.42 $1.26 $1.25
Consolidated Statements of Comprehensive Income (Unaudited)
Net Income $ 136.1 $ 160.9 $ 286.9 $ 292.7
Other comprehensive income (loss), net of taxes 5.0 (0.5) (6.5) (0.6)
---------- ---------- ----------- ----------
Comprehensive Income $ 141.1 $ 160.4 $ 280.4 $ 292.1
========== ========== =========== ==========
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
September 30, December 31,
1999* 1998
-------------- --------------
(In Millions)
ASSETS
Current Assets
Cash and cash equivalents $ 56.4 $ 173.7
Accounts receivable (net of allowance for uncollectibles
of $20.6 and $20.3 respectively) 675.0 401.8
Trading securities 128.4 119.7
Fuel stocks 86.3 85.4
Materials and supplies 149.1 145.1
Prepaid taxes other than income taxes 101.7 68.8
Assets from energy trading activities 431.3 160.2
Other 24.6 21.4
-------------- --------------
Total current assets 1,652.8 1,176.1
-------------- --------------
Investments and Other Assets
Real estate projects and investments 313.3 353.9
Power projects 686.0 656.8
Financial investments 148.8 198.0
Nuclear decommissioning trust fund 205.5 181.4
Net pension asset 97.2 108.0
Other 381.7 243.3
-------------- --------------
Total investments and other assets 1,832.5 1,741.4
-------------- --------------
Utility Plant
Plant in service
Electric 7,053.1 6,890.3
Gas 958.7 921.3
Common 567.7 552.8
-------------- --------------
Total plant in service 8,579.5 8,364.4
Accumulated depreciation (3,256.4) (3,087.5)
-------------- --------------
Net plant in service 5,323.1 5,276.9
Construction work in progress 177.8 223.0
Nuclear fuel (net of amortization) 143.1 132.5
Plant held for future use 12.9 24.3
-------------- --------------
Net utility plant 5,656.9 5,656.7
-------------- --------------
Deferred Charges
Regulatory assets (net) 572.2 565.7
Other 57.3 55.1
-------------- --------------
Total deferred charges 629.5 620.8
-------------- --------------
TOTAL ASSETS $ 9,771.7 $ 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
September 30, December 31,
1999* 1998
-------------- --------------
(In Millions)
LIABILITIES AND CAPITALIZATION
Current Liabilities
Short-term borrowings $ 143.1 $ -
Current portions of long-term debt and preference stock 964.5 541.7
Accounts payable 364.5 249.6
Customer deposits 39.8 35.5
Accrued taxes 52.0 6.5
Accrued interest 62.7 58.6
Dividends declared 66.1 66.1
Accrued vacation costs 34.6 34.7
Liabilities from energy trading activities 310.9 126.2
Other 48.9 45.3
-------------- --------------
Total current liabilities 2,087.1 1,164.2
-------------- --------------
Deferred Credits and Other Liabilities
Deferred income taxes 1,318.1 1,309.1
Postretirement and postemployment benefits 238.0 217.0
Deferred investment tax credits 111.6 118.0
Decommissioning of federal uranium enrichment facilities 30.8 30.8
Other 125.8 56.3
-------------- --------------
Total deferred credits and other liabilities 1,824.3 1,731.2
-------------- --------------
Long-term Debt
BGE first refunding mortgage bonds 1,412.8 1,554.2
BGE other long-term debt 1,135.8 1,000.8
BGE obligated mandatorily redeemable
trust preferred securities 250.0 250.0
Diversified businesses long-term debt 765.5 870.2
Unamortized discount and premium (11.2) (12.4)
Current portion of long-term debt (964.5) (534.7)
-------------- --------------
Total long-term debt 2,588.4 3,128.1
-------------- --------------
BGE Redeemable Preference Stock - 7.0
Current portion of BGE redeemable preference stock - (7.0)
-------------- --------------
Total BGE redeemable preference stock - -
-------------- --------------
BGE Preference Stock Not Subject to Mandatory Redemption 190.0 190.0
-------------- --------------
Common Shareholders' Equity
Common stock 1,493.6 1,485.1
Retained earnings 1,588.7 1,490.3
Accumulated other comprehensive (loss) income (0.4) 6.1
-------------- --------------
Total common shareholders' equity 3,081.9 2,981.5
-------------- --------------
Total capitalization 5,860.3 6,299.6
-------------- --------------
TOTAL LIABILITIES AND CAPITALIZATION $ 9,771.7 $ 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)
Nine Months Ended September 30,
-------------------------------
1999 1998
------------- --------------
(In Millions)
Cash Flows From Operating Activities
Net income $ 286.9 $ 292.7
Adjustments to reconcile to net cash provided by operating activities
Depreciation and amortization 316.2 312.8
Deferred income taxes 20.9 19.4
Investment tax credit adjustments (6.4) (5.5)
Deferred fuel costs (51.2) 1.9
Accrued pension and postemployment benefits 35.5 18.4
Write-down of real estate investment 7.0 -
Write-down of financial investment 26.3 -
Write-off of power project 10.2 -
Equity in earnings of affiliates and joint ventures (net) 22.4 (47.7)
Changes in assets from energy trading activities (271.1) (51.2)
Changes in liabilities from energy trading activities 184.7 49.2
Changes in other current assets (334.6) (47.8)
Changes in other current liabilities 213.9 115.4
Other 22.8 (2.8)
------------- --------------
Net cash provided by operating activities 483.5 654.8
------------- --------------
Cash Flows From Investing Activities
Utility capital expenditures (286.8) (274.9)
Contributions to nuclear decommissioning trust fund (13.2) (13.2)
Purchases of marketable equity securities (17.2) (26.8)
Sales of marketable equity securities 12.5 26.2
Other financial investments 15.1 14.1
Real estate projects and investments 46.2 7.8
Power projects (150.3) (87.6)
Other (48.1) (60.7)
------------- --------------
Net cash used in investing activities (441.8) (415.1)
------------- --------------
Cash Flows From Financing Activities
Proceeds from issuance of
Short-term borrowings 1,761.8 1,962.2
Long-term debt 289.7 447.4
Common stock 9.5 32.5
Repayments of short-term borrowings (1,618.7) (2,154.5)
Reacquisition of long-term debt (399.6) (166.0)
Redemption of preference stock (7.0) (124.9)
Common stock dividends paid (188.3) (183.5)
Other (6.4) (0.4)
------------- --------------
Net cash used in financing activities (159.0) (187.2)
------------- --------------
Net (Decrease) Increase in Cash and Cash Equivalents (117.3) 52.5
Cash and Cash Equivalents at Beginning of Period 173.7 162.6
------------- --------------
Cash and Cash Equivalents at End of Period $ 56.4 $ 215.1
============= ==============
Other Cash Flow Information:
Interest paid (net of amounts capitalized) $ 174.9 $ 170.7
Income taxes paid $ 102.2 $ 108.5
See Notes to Consolidated Financial Statements.
Certain prior period amounts have been reclassified to conform with the current
period's presentation.
6
BALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARIES
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
Consolidated Statements of Income (Unaudited)
Three Months Ended September 30, Nine Months Ended September 30,
1999 1998 1999 1998
----------- ----------- ---------- -----------
(In Millions, Except Per-Share Amounts)
Revenues
Electric $ 691.4 $ 722.5 $ 1,737.5 $ 1,746.8
Gas 62.9 62.1 337.3 324.7
Diversified businesses 1.7 149.4 282.7 496.2
----------- ----------- ---------- -----------
Total revenues 756.0 934.0 2,357.5 2,567.7
Expenses Other Than Interest and Income Taxes
Electric fuel and purchased energy 129.9 149.4 375.3 391.5
Gas purchased for resale 21.3 21.6 156.4 152.0
Operations 126.4 129.4 396.7 395.3
Maintenance 40.7 38.7 142.5 130.8
Diversified businesses - selling, general, and administrative 1.2 122.9 221.3 393.8
Depreciation and amortization 89.0 89.6 267.5 275.6
Taxes other than income taxes 64.2 62.0 175.6 168.6
----------- ----------- ---------- -----------
Total expenses other than interest and income taxes 472.7 613.6 1,735.3 1,907.6
----------- ----------- ---------- -----------
Income From Operations 283.3 320.4 622.2 660.1
Other Income
Allowance for equity funds used during construction 1.5 1.8 5.2 5.0
Equity in earnings of Safe Harbor Water Power Corporation 1.2 1.2 3.8 3.7
Net other income and (deductions) (0.5) 0.5 (3.6) (2.5)
----------- ----------- ---------- -----------
Total other income 2.2 3.5 5.4 6.2
----------- ----------- ---------- -----------
Income Before Interest and Income Taxes 285.5 323.9 627.6 666.3
Interest Expense
Interest charges 48.1 64.1 162.3 186.3
Capitalized interest - (0.7) (0.4) (2.7)
Allowance for borrowed funds used during construction (0.8) (1.0) (2.8) (2.7)
----------- ----------- ---------- -----------
Net interest expense 47.3 62.4 159.1 180.9
------------- ----------- ---------- -----------
Income Before Income Taxes 238.2 261.5 468.5 485.4
Income Taxes
Current 80.5 72.4 169.1 160.5
Deferred 4.9 23.2 3.5 19.4
Investment tax credit adjustments (2.1) (1.8) (6.4) (5.5)
----------- ----------- ---------- -----------
Total income taxes 83.3 93.8 166.2 174.4
----------- ----------- ---------- -----------
Net Income 154.9 167.7 302.3 311.0
Preference Stock Dividends 3.4 6.8 10.2 18.3
----------- ----------- ---------- -----------
Earnings Applicable to Common Stock $ 151.5 $ 160.9 $ 292.1 $ 292.7
=========== =========== ========== ===========
Consolidated Statements of Comprehensive Income (Unaudited)
Net Income $ 154.9 $ 167.7 $ 302.3 $ 311.0
Other comprehensive loss, net of taxes - (0.5) (3.4) (0.6)
----------- ----------- ---------- -----------
Comprehensive Income $ 154.9 $ 167.2 $ 298.9 $ 310.4
=========== =========== ========== ===========
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
September 30 December 31,
1999* 1998
-------------- --------------
(In Millions)
ASSETS
Current Assets
Cash and cash equivalents $ 15.5 $ 173.7
Accounts receivable (net of allowance for uncollectibles
of $13.0 and $20.3 respectively) 352.8 401.8
Trading securities - 119.7
Fuel stocks 86.3 85.4
Materials and supplies 141.0 145.1
Prepaid taxes other than income taxes 101.7 68.8
Assets from energy trading activities - 160.2
Other 10.1 21.4
-------------- --------------
Total current assets 707.4 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 205.5 181.4
Net pension asset 97.3 108.0
Safe Harbor Water Power Corporation 34.5 34.4
Senior living facilities - 93.5
Other 59.7 115.4
-------------- --------------
Total investments and other assets 397.0 1,741.4
-------------- --------------
Utility Plant
Plant in service
Electric 7,053.1 6,890.3
Gas 958.7 921.3
Common 567.7 552.8
-------------- --------------
Total plant in service 8,579.5 8,364.4
Accumulated depreciation (3,256.4) (3,087.5)
-------------- --------------
Net plant in service 5,323.1 5,276.9
Construction work in progress 177.8 223.0
Nuclear fuel (net of amortization) 143.1 132.5
Plant held for future use 12.9 24.3
-------------- --------------
Net utility plant 5,656.9 5,656.7
-------------- --------------
Deferred Charges
Regulatory assets (net) 572.2 565.7
Other 47.0 55.1
-------------- --------------
Total deferred charges 619.2 620.8
-------------- --------------
TOTAL ASSETS $ 7,380.5 $ 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
September 30, December 31,
1999* 1998
-------------- --------------
(In Millions)
LIABILITIES AND CAPITALIZATION
Current Liabilities
Short-term borrowings $ 22.5 $ -
Current portions of long-term debt and preference stock 615.0 541.7
Accounts payable 189.8 249.6
Customer deposits 39.8 35.5
Accrued taxes 54.5 6.5
Accrued interest 47.9 58.6
Dividends declared 3.3 66.1
Accrued vacation costs 34.9 34.7
Liabilities from energy trading activities - 126.2
Other 23.3 45.3
-------------- --------------
Total current liabilities 1,031.0 1,164.2
-------------- --------------
Deferred Credits and Other Liabilities
Deferred income taxes 1,062.7 1,309.1
Postretirement and postemployment benefits 229.2 217.0
Deferred investment tax credits 111.6 118.0
Decommissioning of federal uranium enrichment facilities 30.8 30.8
Other 57.6 56.3
-------------- --------------
Total deferred credits and other liabilities 1,491.9 1,731.2
-------------- --------------
Long-term Debt
First refunding mortgage bonds of BGE 1,412.8 1,554.2
Other long-term debt of BGE 1,135.8 1,000.8
Company obligated mandatorily redeemable
trust preferred securities 250.0 250.0
Long-term debt of diversified businesses 33.0 870.2
Unamortized discount and premium (11.2) (12.4)
Current portion of long-term debt (614.9) (534.7)
-------------- --------------
Total long-term debt 2,205.5 3,128.1
-------------- --------------
Redeemable Preference Stock - 7.0
Current portion of redeemable preference stock - (7.0)
-------------- --------------
Total redeemable preference stock - -
-------------- --------------
Preference Stock Not Subject to Mandatory Redemption 190.0 190.0
-------------- --------------
Common Shareholder's Equity
Common stock 1,493.6 1,485.1
Retained earnings 968.5 1,490.3
Accumulated other comprehensive income - 6.1
-------------- --------------
Total common shareholder's equity 2,462.1 2,981.5
-------------- --------------
Total capitalization 4,857.6 6,299.6
-------------- --------------
TOTAL LIABILITIES AND CAPITALIZATION $ 7,380.5 $ 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)
Nine Months Ended September 30,
-------------------------------
1999 1998
------------ ------------
(In Millions)
Cash Flows From Operating Activities
Net income $ 302.3 $ 311.0
Adjustments to reconcile to net cash provided by operating activities
Depreciation and amortization 307.6 312.8
Deferred income taxes 3.6 19.4
Investment tax credit adjustments (6.4) (5.5)
Deferred fuel costs (51.2) 1.9
Accrued pension and postemployment benefits 35.0 18.4
Allowance for equity funds used during construction (5.2) (5.0)
Equity in earnings of affiliates and joint ventures (net) 29.0 (47.7)
Changes in assets from energy trading activities (120.1) (51.2)
Changes in liabilities from energy trading activities 76.3 49.2
Changes in other current assets (73.2) (47.8)
Changes in other current liabilities 41.9 115.4
Other 32.5 1.5
------------ ------------
Net cash provided by operating activities 572.1 672.4
------------ ------------
Cash Flows From Investing Activities
Utility construction expenditures (including AFC) (246.1) (215.7)
Allowance for equity funds used during construction 5.2 5.0
Nuclear fuel expenditures (45.0) (49.0)
Deferred energy conservation expenditures (0.9) (15.2)
Contributions to nuclear decommissioning trust fund (13.2) (13.2)
Purchases of marketable equity securities (9.2) (26.8)
Sales of marketable equity securities 6.0 26.2
Other financial investments 6.7 14.1
Real estate projects and investments 22.0 7.8
Power projects (17.9) (87.6)
Other (16.7) (60.7)
------------ ------------
Net cash used in investing activities (309.1) (415.1)
------------ ------------
Cash Flows From Financing Activities
Proceeds from issuance of
Short-term borrowings 1,608.3 1,962.2
Long-term debt 257.2 447.4
Common stock 9.5 32.5
Repayments of short-term borrowings (1,585.8) (2,154.5)
Reacquisition of long-term debt (375.3) (166.0)
Redemption of preference stock (7.0) (124.9)
Common stock dividends paid (188.3) (183.5)
Preference stock dividends paid (10.3) (17.6)
Distribution of cash to Constellation Energy (128.2) -
Other (1.3) (0.4)
------------ ------------
Net cash used in financing activities (421.2) (204.8)
------------ ------------
Net (Decrease) Increase in Cash and Cash Equivalents (158.2) 52.5
Cash and Cash Equivalents at Beginning of Period 173.7 162.6
------------ ------------
Cash and Cash Equivalents at End of Period $ 15.5 $ 215.1
============ ============
Other Cash Flow Information:
Interest paid (net of amounts capitalized) $ 155.0 $ 170.7
Income taxes paid $ 99.4 $ 108.5
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,
Constellation Enterprises, Inc. and its subsidiaries, and Constellation Nuclear
Services, Inc. The consolidated financial statements of BGE include the accounts
of BGE, District Chilled Water General Partnership (ComfortLink), and BGE
Capital Trust I. As Constellation Enterprises and its subsidiaries were
subsidiaries of BGE prior to April 30, 1999, they are included in the
consolidated financial statements of BGE through that date.
References in this report to "we" and "our" are to Constellation Energy and
its subsidiaries, collectively. Reference in this report to the "utility
business" is to BGE.
Deregulation of Electric Generation
- -----------------------------------
On November 10, 1999, the Maryland PSC issued a Restructuring Order that
resolves the major issues surrounding electric restructuring. See the
"Competition and Response to Regulatory Change" section on page 20 for a
detailed discussion of the Restructuring Order.
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 September 30, (in millions)
1999
Unaffiliated revenues $ 691.2 $ 60.1 $ 222.6 $ (3.5) $ - $ - $ 970.4
Intersegment revenues 0.2 2.8 14.7 (0.2) - (17.5) -
----------- ------------ ------------- --------------- -------------- ------------- ---------------
Total revenues 691.4 62.9 237.3 (3.7) - (17.5) 970.4
Net income (loss) 152.3 (0.7) 7.2 (22.2) (0.5) - 136.1
Segment assets 6,409.0 928.5 1,720.6 736.9 (16.5) (6.8) 9,771.7
1998
Unaffiliated revenues $ 722.5 $ 62.1 $ 130.9 $ 18.5 $ - $ - $ 934.0
Intersegment revenues 1.2 - 10.3 (0.9) - (10.6) -
----------- ------------ ------------- --------------- -------------- ------------- ---------------
Total revenues 723.7 62.1 141.2 17.6 - (10.6) 934.0
Net income (loss) 155.6 (1.8) 18.1 (11.1) 0.1 - 160.9
Segment assets 6,467.0 932.7 1,057.0 827.7 (29.2) (111.2) 9,144.0
11
Energy Other Unallocated
Electric Gas Services Diversified Corporate
Business Business Businesses Businesses Items (a) Eliminations Consolidated
------------ ------------ ------------- --------------- -------------- ------------- ---------------
For the nine months ended September 30, (in millions)
1999
Unaffiliated revenues $ 1,737.2 $ 332.7 $ 581.3 $ 71.4 $ - $ - $ 2,722.6
Intersegment revenues 0.7 7.4 27.0 (0.4) - (34.7) -
----------- ------------ ------------- --------------- -------------- ------------- ---------------
Total revenues 1,737.9 340.1 608.3 71.0 - (34.7) 2,722.6
Net income (loss) 253.4 21.5 42.2 (28.9) (1.3) - 286.9
Segment assets 6,409.0 928.5 1,720.6 736.9 (16.5) (6.8) 9,771.7
1998
Unaffiliated revenues $ 1,746.8 $ 324.7 $ 365.8 $ 130.4 $ - $ - $ 2,567.7
Intersegment revenues 1.3 - 10.8 (0.6) - (11.5) -
----------- ------------ ------------- --------------- -------------- ------------- ---------------
Total revenues 1,748.1 324.7 376.6 129.8 - (11.5) 2,567.7
Net income (loss) 249.0 15.6 36.6 (8.6) 0.1 - 292.7
Segment assets 6,467.0 932.7 1,057.0 827.7 (29.2) (111.2) 9,144.0
(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 $9.5 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. As of the date of this report, letters of credit
totaling $23.7 million were issued under this facility.
As of the date of this report, Constellation Energy has issued guarantees in
an amount up to $49.7 million to support the contractual performance of certain
of its diversified subsidiaries.
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
Floating rate, due 2000 150.0 9/99 149.8
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 31 for information about
the debt of our diversified businesses.
12
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 $104 million of this commitment.
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 will 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 1, 2000. 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. This rule was appealed by several groups
including utilities and states. 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 MDE's 65% NOx
emission reduction requirements will cost approximately $135 million. Through
the date of this report, we have spent approximately $38 million to meet MDE's
65% reduction requirements. We estimate the additional cost for EPA's 85%
reduction requirements to be approximately $35 million.
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 15.43% share of the reasonably
possible cleanup costs at one of these sites, Metal Bank of America (a metal
reclaimer in Philadelphia), could be as much as $4.9 million higher than amounts
we have recorded as a liability on our Consolidated Balance Sheets. This
estimate is based on a Record of Decision issued by the EPA.
On July 12, 1999, the EPA notified us, along with nineteen other entities,
that we may be a potentially responsible party at the 68th Street Dump Site,
also known as the Robb Tyler Dump located in Baltimore, Maryland. The EPA
indicated that it is proceeding with plans to conduct a remedial investigation
and feasibility study. This site was proposed for listing on the federal
Superfund list in January 1999, but the list has not been finalized. Although
our potential liability cannot be estimated, we do not expect such liability to
be material based on our records showing that we did not send waste to the site.
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 liability on
our Consolidated Balance Sheets and have
13
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 industry standard exclusions. Furthermore, the costs that could
result from a covered major accident or a covered extended outage at either of
the Calvert Cliffs units could exceed our insurance coverage limits.
Insurance for Calvert Cliffs and Third Party Claims
- ---------------------------------------------------
For physical damage to Calvert Cliffs, we have $2.75 billion of property
insurance from an industry mutual insurance company. If an outage at either of
the two units at Calvert Cliffs is caused by an insured physical damage loss and
lasts more than 12 weeks, we have insurance coverage for replacement power costs
up to $490.0 million per unit, provided by an industry mutual insurance company.
This amount can be reduced by up to $98.0 million per unit if an outage at both
units of the plant is caused by a single insured physical damage loss. If
accidents at any insured plants cause a shortfall of funds at the industry
mutual insurance company, all policyholders could be assessed, with our share
being up to $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
- -------------------------------------
Historically and until July 1, 2000, 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.
Under the terms of the Restructuring Order, BGE's electric fuel rate clause
will be discontinued effective July 1, 2000. After that date, earnings will be
affected by 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. The discontinuance of BGE's electric fuel rate clause is discussed further
in the "Regulation by the Maryland PSC" section in Management's Discussion and
Analysis on page 18.
California Power Purchase Agreements
- ------------------------------------
Constellation Power, Inc. and subsidiaries and Constellation Investments,
Inc. (whose power projects are managed by Constellation Power) have $308.2
million invested in 14 projects that sell electricity in California under power
purchase agreements called "Interim Standard Offer No. 4" agreements. Under
these agreements, the projects supply electricity to utility companies at:
o a fixed rate for capacity and energy for the first 10 years of the
agreements, and
o a fixed rate for capacity plus a variable rate for energy based on the
utilities' avoided cost for the remaining term of the agreements.
Generally, a "capacity rate" is paid to a power plant for its availability
to supply electricity, and an "energy rate" is paid for the electricity actually
generated. "Avoided cost" generally is the cost of a utility's cheapest
next-available source of generation to service the demands on its system.
We use the term "transition period" to describe the time frame when the
10-year periods for fixed energy rates expire for these 14 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.
We discuss the earnings for these projects in the "Diversified Businesses"
section beginning on page 26.
Other Diversified Businesses
- ----------------------------
We discuss our other diversified businesses' activities further in the
"Diversified Businesses" section beginning on page 26.
15
Item 2. Management's Discussion
Management's Discussion and Analysis of Financial Condition and Results of
Operations
- --------------------------------------------------------------------------------
Introduction
- ------------
On April 30, 1999, Constellation Energy(R) Group, Inc. (Constellation
Energy) became the holding company for Baltimore Gas and Electric Company
(BGE(R)) and Constellation(R) Enterprises, Inc. Constellation Enterprises was
previously owned by BGE.
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 Constellation Nuclear Services, (TM) Inc. -- our nuclear consulting
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. The consolidated financial statements of Constellation Energy
include the accounts of Constellation Energy, BGE and its subsidiaries,
Constellation Enterprises, Inc. and its subsidiaries, and Constellation Nuclear
Services, Inc. The consolidated financial statements of BGE include the accounts
of BGE, ComfortLink, and BGE Capital Trust I. As Constellation Enterprises and
its subsidiaries were subsidiaries of BGE prior to April 30, 1999, they are
included in the consolidated financial statements of BGE through that date.
References in this report to "we" and "our" are to Constellation Energy and
its subsidiaries, collectively. Reference in this report to the "utility
business" is to BGE.
Deregulation and Strategy
- -------------------------
The electric utility industry is undergoing rapid and substantial change. On
April 8, 1999, Maryland enacted legislation authorizing customer choice and
competition among electric suppliers. 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. On November 10, 1999, the Maryland PSC issued a Restructuring
Order that approved 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. Also, upon receipt of all regulatory approvals, on July 1, 2000, all of
BGE's generation assets will be moved to nonregulated subsidiaries of
Constellation Energy. These assets represent about 6,240 megawatts of generation
capacity. These matters are discussed further in the "Competition and Response
to Regulatory Change" section on page 20.
In Maryland, all gas customers were able to choose suppliers beginning
November 1, 1999.
This change toward customer choice will significantly impact our business
going forward. In response to this change, we regularly evaluate our strategies
with two goals in mind: to improve our competitive position, and to anticipate
and adapt to regulatory change. We will continue to invest in the growth of our
nonregulated businesses, especially our power projects and power marketing and
trading businesses, with the objective of providing new sources of earnings in
anticipation of lower electric utility revenues. In addition, we might consider
one or more of the following strategies:
16
o the complete or partial separation of our transmission and distribution
functions,
o the construction, purchase or sale of generation assets,
o mergers or acquisitions of utility or non-utility businesses,
o spin-off or sale of one or more businesses, and
o growth of earnings from other nonregulated businesses.
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. However, with the shift toward customer choice, competition, and the
growth of our nonregulated subsidiaries, various factors will affect our results
of operations and financial condition in the future. These factors include, but
are not limited to, the loss of customers, higher volatility of earnings and
cash flows, and increased financial requirements of our nonregulated
subsidiaries. Please refer to the "Forward Looking Statements" section on page
38. 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, refer to our Consolidated
Statements of Income on page 3, which present the results of our operations for
the quarters and nine months ended September 30, 1999 and 1998. We analyze and
explain the differences between periods in the specific line items of the
Consolidated Statements of Income. Our analysis is important in making decisions
about your investments in Constellation Energy.
Also, this discussion and analysis is based on the operation of the
electric generation portion of our utility business under current rate
regulation. Our electric business will change significantly beginning July 1,
2000 as we enter into the transition to full retail customer choice for electric
generation. Accordingly, the results of operations and financial condition
described in this discussion and analysis are not necessarily indicative of
future performance.
- -------------------------------------------------------------------------------
Results of Operations for the Quarter and Nine Months Ended September 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 Nine Months Ended
September 30 September 30
--------------- ----------------
1999 1998 1999 1998
------- ------- -------- -------
Utility business...... $1.02 $1.03 $1.84 $1.78
Diversified businesses (.11) .05 .08 .19
---- --- --- ---
Total earnings
per share.......... $ .91 $1.08 $1.92 $1.97
====== ===== ===== =====
Quarter Ended September 30, 1999
- --------------------------------
Our total earnings for the quarter ended September 30, 1999 decreased $24.8
million, or $.17 per share, compared to the same period of 1998.
In the third quarter of 1999, we had lower utility earnings compared to the
same period of 1998 mostly because we deferred $37.5 million of electric
revenues to reflect certain terms of the proposed settlement agreement with the
Maryland PSC, and we incurred costs associated with Hurricane Floyd. This
decrease in utility earnings compared to 1998 was partially offset by the
settlement of a capacity contract with PECO Energy Company (PECO) in the third
quarter of 1998. We discuss our utility earnings in more detail in the "Utility
Business" section on page 18.
17
In the third quarter of 1999, diversified business earnings decreased
compared to the same period of 1998 mostly because of lower earnings from our
power projects and financial investments businesses. This decline was partially
offset by higher earnings from our power marketing and trading business. We
discuss our diversified business earnings further in the "Diversified
Businesses" section beginning on page 26.
Nine Months Ended September 30, 1999
- ------------------------------------
Our total earnings for the nine months ended September 30, 1999 decreased
$5.8 million, or $.05 per share, compared to the same period of 1998.
In the nine months ended September 30, 1999, we had higher utility earnings
compared to the same period of 1998 mostly because we sold more electricity and
gas this year and we settled a capacity contract with PECO in 1998. The increase
in utility earnings was partially offset by the deferral of $37.5 million of
electric revenues as discussed above, and higher operations and maintenance
expenses mostly due to Hurricane Floyd and a major winter ice storm. We discuss
our utility earnings in more detail in the "Utility Business" section below.
In the nine months ended September 30, 1999, diversified business earnings
decreased compared to the same period of 1998 mostly because of lower earnings
from our power projects and financial investments businesses. This decline was
partially offset by higher earnings from our power marketing and trading
business. We discuss our diversified business earnings further in the
"Diversified Businesses" section beginning on page 26.
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 Restructuring Order, BGE's electric base rates are frozen at
the current levels until July 1, 2000. At that time, electric residential
customer choice begins and residential base rates will decrease by about $54
million per year. 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. Under the Restructuring Order, the electric conservation
surcharge and associated profit limitation will be discontinued effective July
1, 2000.
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.
18
We discuss this in more detail 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.
Under the Restructuring Order, BGE's electric fuel rate clause will be
discontinued effective July 1, 2000. After that date, 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 over a period to be determined by the Maryland PSC.
At September 30, 1999, BGE's actual costs of fuel and energy were $66.1 million
higher than the electric fuel rate revenues collected from customers.
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.
Please refer to the "Competition and Response to Regulatory Change" section
on page 20 for a detailed discussion of the Restructuring Order.
Weather
- -------
Weather affects the demand for electricity and gas. Very hot summers and
very cold winters increase demand. Mild weather reduces demand. Weather impacts
residential sales more than commercial and industrial sales, which are mostly
affected by business needs for electricity and gas.
We measure the weather's effect using "degree days." A degree day is the
difference between the average daily actual temperature and a baseline
temperature of 65 degrees. Cooling degree days result when the average daily
actual temperature exceeds the 65 degree baseline. Heating degree days result
when the average daily actual temperature is less than the baseline.
During the cooling season, hotter weather is measured by more cooling degree
days and results in greater demand for electricity to operate cooling systems.
During the heating season, colder weather is measured by more heating degree
days and results in greater demand for electricity and gas to operate heating
systems.
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
nine months ended September 30, 1999 and 1998 and the percentage change in the
number of degree days between these periods in the following table:
Quarter Ended Nine Months Ended
September 30 September 30
--------------- ------------------
1999 1998 1999 1998
-------- ------ -------- --------
Heating degree days... 75 74 2,981 2,559
Percent change
compared to prior period 1.4% 16.5%
Cooling degree days... 629 625 832 904
Percent change
compared to prior period 0.6% (8.0)%
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.
19
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 and the accompanying tax
legislation are discussed in detail in our June 30, 1999 Quarterly Report on
Form 10-Q.
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 PSC. On November 10, 1999, the Maryland PSC issued a Restructuring
Order that approved the proposed settlement agreement. The Restructuring Order
resolves 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 Restructuring Order accelerates the timetable for
customer choice and addresses certain other provisions of the Act. There is a
30-day period to file an appeal to the Restructuring Order. We cannot predict
whether an appeal will be filed. 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 Restructuring Order 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 and utility restructuring costs through a competitive
transition charge on customers' bills. Residential customers will pay
this charge for six years. Commercial and industrial customers will pay
in a lump sum or over the four to six-year period, depending on the
service option selected by each customer.
o Generation-related regulatory assets and nuclear decommissioning costs
will be included in delivery service rates effective July 1, 2000 and
will be recovered on a basis approximating their existing amortization
schedules.
o Starting July 1, 2000, BGE will unbundle rates to show separate
components for delivery service, transition charges, standard offer
services (generation), transmission, universal service, and taxes.
o 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
nonregulated subsidiaries of Constellation Energy.
o BGE will reduce its generation assets, as described later in this
section, by $150 million (pre-tax) during the period July 1, 1999 - June
30, 2000 to mitigate a portion of BGE's potentially stranded
investments.
o Universal service is provided for low-income customers without
increasing their bills. BGE will provide its share of a statewide fund
totaling $34 million.
We believe that the Restructuring Order provides sufficient details of the
transition plan to competition for BGE's electric generation business to require
BGE to discontinue the application of Statement of Financial Accounting
Standards (SFAS) No. 71, Accounting for the Effects of Certain Types of
Regulation for that portion of our business. Accordingly, in the fourth quarter
of 1999, we will adopt the provisions of SFAS No. 101, Regulated
20
Enterprises - Accounting for the Discontinuation of FASB Statement No. 71 and
Emerging Issues Task Force Consensus (EITF) No. 97-4, Deregulation of the
Pricing of Electricity - Issues Related to the Application of FASB Statements
No. 71 and 101 for BGE's electric generation business. BGE's transmission and
distribution business continues to meet the requirements of SFAS No. 71 as that
business remains regulated. We describe the effect of applying these accounting
requirements in the following discussion.
SFAS No. 101 requires the elimination of the effects of rate regulation that
have been recognized as regulatory assets and liabilities pursuant to SFAS No.
71. Under the Restructuring Order, BGE's generation-related net regulatory
assets will be effectively recovered through BGE's regulated transmission and
distribution business. We expect that there will be no net impact on BGE's or
Constellation Energy's earnings associated with the recovery of the
generation-related net regulatory assets.
Pursuant to SFAS No. 101, the book value of property, plant, and equipment
may not be adjusted unless those assets are impaired under the provisions of
SFAS No. 121, Accounting for the Impairment of Long-Lived Assets and for
Long-Lived Assets To Be Disposed Of. The process of evaluating and measuring
impairment under the provisions of SFAS No. 121 involves two steps. First, we
must compare the net book value of each generating plant to the estimated
undiscounted future net operating cash flows from that plant. An electric
generating plant is considered impaired when its undiscounted future net
operating cash flows are less than its net book value. Second, we compute the
fair value of each plant that is determined to be impaired based on the present
value of that plant's estimated future net operating cash flows discounted using
an interest rate that considers the risk of operating that facility in a
competitive environment. To the extent that the net book value of each impaired
electric generation plant exceeds its fair value, we must record a write-down.
Under the Restructuring Order, BGE will recover $528 million of its
potentially stranded investments and utility restructuring costs through the
competitive transition charge component of its customer rates beginning July 1,
2000. This recovery mostly relates to the stranded costs associated with BGE's
Calvert Cliffs Nuclear Power Plant, whose book value is substantially higher
than its estimated fair value. However, Calvert Cliffs is not considered
impaired under the provisions of SFAS No. 121 since its estimated future
undiscounted cash flows exceed its book value. Accordingly, BGE will not record
any impairment write-down related to Calvert Cliffs. We will, however, recognize
impairment losses associated with certain of our fossil plants under the
provisions of SFAS No. 121.
BGE has contracts to purchase electric capacity and energy that are expected
to be uneconomic upon the deregulation of electric generation. Therefore, we
must record a charge based on the net present value of the excess of estimated
contract costs over the market-based revenues to recover these costs over the
remaining terms of the contracts. In addition, BGE has deferred certain energy
conservation expenditures that will not be recovered through its transmission
and distribution business under the Restructuring Order. Accordingly, we must
record a charge to eliminate the regulatory asset previously established for
these deferred expenditures.
At the date of this report, we estimate that the total charge for BGE's
electric generating plants that are impaired, losses on uneconomic purchased
capacity and energy contracts, and deferred energy conservation expenditures is
approximately $150 million to $175 million (after-tax). The actual charge will
be recorded in the fourth quarter of 1999.
BGE will record approximately $95 million of this charge on its balance
sheet. This will consist of establishing a $150 million regulatory asset of its
regulated transmission and distribution business, net of approximately $55
million of associated deferred income taxes. The regulatory asset will be
amortized as it is recovered from ratepayers through June 30, 2000. This will
accomplish the $150 million reduction of its generation plants required by the
Restructuring Order.
We will record an after-tax, extraordinary charge against earnings for the
approximately $55 million to $80 million remaining portion of the $150 million
to $175 million described above that will not be recovered under the
Restructuring Order.
As a condition of the Maryland PSC's consolidation of the September 3, 1998
Office of People's Counsel petition to lower electric base rates with BGE's
electric restructuring transition proposal, we agreed to make our rates subject
to refund effective July 1, 1999. Therefore, BGE deferred $37.5 million of
revenues it collected during the third quarter pending the Maryland PSC's
approval of the proposed settlement. However, with the issuance of the
Restructuring Order, these deferred revenues will be reversed in the fourth
quarter, as our current rates will be frozen through June 30, 2000. In the
fourth quarter, BGE will also record $75 million in amortization expense or
one-half of the $150 million reduction of generation plants provided for in the
Restructuring Order as discussed above.
21
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 effective
November 1, 1999, all BGE residential customers, have the option to purchase gas
from other suppliers.
Utility Business Earnings per Share of Common Stock
- ---------------------------------------------------
Quarter Ended Nine Months Ended
September 30 September 30
--------------- ------------------
1999 1998 1999 1998
-------- ------- -------- -------
Electric business... $1.02 $1.04 $1.70 $1.67
Gas business........ - (.01) .14 .11
---- ---- --- ---
Total utility
earnings per share $1.02 $1.03 $1.84 $1.78
===== ===== ===== =====
Our utility earnings for the quarter ended September 30, 1999 decreased $2.0
million, or $.01 per share compared to the same period of 1998. Our utility
earnings for the nine months ended September 30, 1999, increased $10.3 million,
or $.06 per share compared to the same period of 1998. We discuss the factors
affecting utility earnings below.
The discussion below reflects the operations of the electric generation
portion of our utility business under current rate regulation by the Maryland
PSC. Our electric business will change significantly beginning July 1, 2000 as
we enter into the transition to full retail customer choice for electric
generation. Also, upon receipt of all regulatory approvals, on July 1, 2000, all
of BGE's generation assets will be moved to nonregulated subsidiaries of
Constellation Energy. These assets represent about 6,240 megawatts of generation
capacity. We have not determined the impact of transferring all of BGE's
generation assets to nonregulated subsidiaries on BGE's assets, revenues and net
income. However, such amounts could be material. We discuss this further in the
"Deregulation and Strategy" section on page 16.
Electric Operations
- -------------------
Electric Revenues
- -----------------
The changes in electric revenues in 1999 compared to 1998 were caused by:
Quarter Ended Nine Months Ended
September 30 September 30
1999 vs. 1998 1999 vs. 1998
--------------- ------------------
(In millions)
Electric system
sales volumes....... $ 7.7 $ 25.7
Base rates............ 10.8 10.3
Fuel rates............ (1.0) 0.9
---- ---
Total change in electric
revenues from electric
system sales........ 17.5 36.9
Interchange and
other sales......... (11.7) (10.6)
Other................. (37.1) (35.9)
----- -----
Total change in
electric revenues... $(31.3) $ (9.6)
====== ======
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 Nine Months Ended
September 30 September 30
1999 vs. 1998 1999 vs. 1998
--------------- --------------------
Residential.......... 3.5% 4.3%
Commercial........... 0.2 1.4
Industrial........... (11.9) (7.3)
During the quarter ended September 30, 1999, we sold more electricity to
residential customers due to higher usage per customer and warmer weather. We
sold about the same amount of electricity to 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 from June to August for a planned upgrade to their facilities
that temporarily reduced their electricity consumption.
22
During the nine months ended September 30, 1999, we sold more electricity to
residential customers due to higher usage per customer, colder winter weather,
and an increased number of customers. The increase in sales to residential
customers was partially offset by milder spring and early summer weather. We
sold more electricity to commercial customers mostly due to colder winter
weather and an increased number of customers. We sold less electricity to
industrial customers mostly because usage by Bethlehem Steel and other
industrial customers decreased.
Base Rates
- ----------
During the quarter and nine months ended September 30, 1999, base rate
revenues increased compared to the same periods of 1998 mostly because we had
higher conservation surcharge revenues.
Fuel Rates
- ----------
During the quarter and nine months ended September 30, 1999, fuel rate
revenues were about the same compared to the same periods of 1998.
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 six 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 and nine months ended September 30, 1999, we had lower
interchange and other sales compared to the same periods of 1998 mostly because
the increased demand for system sales reduced the amount of energy we had
available for off-system sales.
Other
- -----
During the quarter and nine months ended September 30, 1999, other revenues
decreased compared to the same periods of 1998 mostly because BGE deferred $37.5
million of electric revenues that it collected during the third quarter of 1999
on the basis that as of September 30, 1999 this amount was subject to refund
pending the Maryland PSC's approval of the proposed settlement agreement. We
discuss the revenue deferral further in the "Competition and Response to
Regulatory Change" section on page 20.
Electric Fuel and Purchased Energy Expenses
- -------------------------------------------
Quarter Ended Nine Months Ended
September 30 September 30
----------------- ------------------
1999 1998 1999 1998
-------- ------- ------- ---------
(In millions)
Actual costs......... $177.6 $169.9 $435.4 $408.6
Net deferral of costs
under electric fuel
rate clause (see
Note 1 of BGE's
1998 Form 10-K).... (61.8) (20.5) (78.5) (17.1)
----- ----- ----- -----
Total electric fuel and
purchased energy
expenses........... $115.8 $149.4 $356.9 $391.5
====== ====== ====== ======
Actual Costs
- ------------
During the quarter and nine months ended September 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. The increase in actual costs
was partially offset by our settlement of a capacity contract with PECO in 1998.
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 nine months ended September 30, 1999, our actual
costs of fuel and energy were higher than the fuel rate revenues we collected
from our customers.
23
Gas Operations
- --------------
Gas Revenues
- ------------
The changes in gas revenues in 1999 compared to 1998 were caused by:
Quarter Ended Nine Months Ended
September 30 September 30
1999 vs. 1998 1999 vs. 1998
--------------- ------------------
(In millions)
Gas system
sales volumes....... $ 1.0 $ 7.3
Base rates............ (0.3) 2.0
Weather normalization. 0.6 4.1
Gas cost adjustments.. 2.2 15.0
--- ----
Total change in gas
revenues from gas
system sales........ 3.5 28.4
Off-system sales...... (5.8) (20.9)
Other................. 0.3 0.5
--- ---
Total change in
gas revenues........ $(2.0) $ 8.0
===== =====
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 Nine Months Ended
September 30 September 30
1999 vs. 1998 1999 vs. 1998
--------------- ------------------
Residential........ 0.7% 9.1%
Commercial......... 8.5 12.7
Industrial......... (10.6) (6.3)
During the quarter ended September 30, 1999, we sold about the same amount
of gas to residential customers as we did during the same period of 1998. We
sold more gas to commercial customers due to higher 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. Usage
by Bethlehem Steel decreased due to a shut down from June to August for a
planned upgrade to their facilities.
During the nine months ended September 30, 1999, we sold more gas to
residential customers mostly because of two factors: colder winter weather and
the number of customers increased. This was partially offset by 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 September 30, 1999, base rate revenues were about
the same compared to the same period of 1998.
During the nine months ended September 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 on page 23.
However, under market based rates, our actual cost of gas is compared to a
market index (a measure of the market price of gas in a given period). The
difference between our actual cost and the market index is shared equally
between shareholders and customers, and does not significantly impact earnings.
Delivery service customers, including Bethlehem Steel, are not subject to
the gas cost adjustment clauses because we are not selling gas to them. We
charge these customers fees to recover the fixed costs for the transportation
service we provide. These fees are the same as the base rate charged for gas
sales and are included in gas system sales volumes.
During the quarter ended September 30, 1999, gas cost adjustment revenues
increased compared to the same period of 1998 mostly because we sold gas at a
higher price.
24
During the nine months ended September 30, 1999, gas cost adjustment
revenues increased compared to the same period 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 nine months ended September 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 Nine Months Ended
September 30 September 30
------------------ ------------------
1999 1998 1999 1998
-------- -------- ------- --------
(In millions)
Actual costs........ $ 19.1 $ 19.4 $142.1 $148.5
Net recovery of
costs under gas
adjustment clauses 2.2 2.2 14.3 3.5
-------- -------- -------- ---------
Total gas
purchased for
resale expenses.. $ 21.3 $ 21.6 $156.4 $152.0
======== ======== ======= ========
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 nine months ended
September 30, 1999, actual gas costs decreased compared to the same periods 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 nine months ended September 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 September 30, 1999, operations and maintenance
expenses were about the same compared to the same period of 1998. In 1999,
operations and maintenance expenses include approximately $7.5 million of costs
associated with Hurricane Floyd. This was offset by higher operations and
maintenance expenses in the third quarter of 1998 associated with the annual
refueling outage at Calvert Cliffs.
During the nine months ended September 30, 1999, operations and maintenance
expenses increased $14.8 million compared to the same period of 1998 mostly
because of costs related to Hurricane Floyd and a major winter ice storm during
1999. This increase was partially offset by the $6.5 million write-off of
contributions to a third party for a low-level radiation waste facility that was
never completed, which we recorded in 1998.
Depreciation and Amortization Expenses
- --------------------------------------
During the quarter and nine months ended September 30, 1999, depreciation
and amortization expenses were about the same compared to the same periods of
1998.
Taxes Other Than Income Taxes
- -----------------------------
During the quarter ended September 30, 1999, taxes other than income taxes
increased $3.1 million compared to the same period of 1998 mostly because of
higher property taxes.
During the nine months ended September 30, 1999, taxes other than income
taxes increased $8.6 million compared to the same period of 1998 mostly because
of two factors: higher property taxes and higher payroll taxes associated with
increased labor costs.
Interest Expense
- ----------------
During the quarter and nine months ended September 30, 1999, interest
expense was about the same compared to the same periods of 1998.
25
Income Taxes
- ------------
During the quarter ended September 30, 1999, our total income taxes
decreased $16.1 million compared to the same period of 1998 mostly because we
had lower taxable income from our diversified businesses.
During the nine months ended September 30, 1999, our total income taxes
decreased $7.3 million compared to the same period of 1998 mostly because we had
lower taxable income from our diversified businesses partially offset by higher
taxable income from our utility operations.
Diversified Businesses
- ----------------------
Our diversified businesses engage primarily in energy services. We list each
of our diversified businesses in the "Introduction" section on page 16. 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 Nine Months Ended
September 30 September 30
----------------- -----------------
1999 1998 1999 1998
-------- ------- ------- -------
Energy services
Power marketing
and trading... $ .06 $ (.01) $ .19 $ -
Power projects. .03 .13 .13 .25
Other.......... (.04) - (.04) -
-------- -------- -------- --------
Total energy
services earnings
per share..... .05 .12 .28 .25
Other diversified
businesses
earnings per
share.......... (.16) (.07) (.20) (.06)
---- ---- ---- ----
Total earnings
per share...... $(.11) $.05 $.08 $.19
======== ======== ======== ========
Our total diversified business earnings for the quarter ended September 30,
1999 decreased $22.8 million, or $.16 per share, compared to the same period of
1998. Our total diversified business earnings for the nine months ended
September 30, 1999 decreased $16.1 million, or $.11 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 nine months ended September 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 September 30, 1999 compared to December 31, 1998 because of greater
business activity during the period.
26
Power Projects
- --------------
During the quarter and nine months ended September 30, 1999, earnings from
our power projects business decreased compared to the same periods of 1998
mostly because of two factors:
o In August 1999, our power projects business recorded a $6.7 million
after-tax, or $.05 per share write-off of a geothermal power project.
The write-off occurred because the expected future cash flow from the
project is less than the investment in the project as a result of
declining water temperature of the geothermal resource used by the plant
for production.
o In July 1998, our power projects business recorded a $10.4 million
after-tax, or $.07 per share, gain for its share of earnings in a
partnership. The partnership recognized a gain on the sale of a power
purchase agreement.
California Power Purchase Agreements
- ------------------------------------
Constellation Power and subsidiaries and Constellation Investments have
$308.2 million invested in 14 projects that sell electricity in California under
power purchase agreements called "Interim Standard Offer No. 4" agreements.
Earnings from these projects were $12.4 million, or $.08 per share, for the
quarter ended September 30, 1999 compared to $24.0 million, or $.16 per share
for the same period of 1998. Earnings from these projects were $26.3 million, or
$.18 per share, for the nine months ended September 30, 1999 compared to $41.0
million, or $.28 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 continue 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.
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 four projects that have the highest revenues will
transition between February and December 2000. The projects which transitioned
in 1999 contributed $2.1 million, or $.01 per share to the quarter ended
September 30, 1999 earnings and $5.4 million, or $.04 per share for the nine
months ended September 30, 1999 earnings. Those changing over in 2000
contributed $9.9 million, or $.07 per share to the quarter ended September 30,
1999 earnings and $20.4 million, or $.14 per share for the nine months ended
September 30, 1999 earnings. We expect earnings ultimately to decrease by
similar amounts as these projects transition.
We also describe these projects and the transition process in the Notes to
Consolidated Financial Statements on page 15.
International
- -------------
At September 30, 1999, Constellation Power had invested about $182.0 million
in 10 power projects in Latin America compared to $104.4 million invested in
Latin America at September 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 nine months ended September 30, 1999, earnings from
our other energy services businesses decreased compared to the same periods of
1998 mostly because of lower gross margins from energy trading at our energy
products and services business.
27
Other Diversified Businesses
- ----------------------------
During the quarter and nine months ended September 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 would 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.
In September 1999, our financial investments business wrote-down its
investment in Capital Re stock by an additional $17.3 million after-tax, or $.12
per share to reflect the market value of $12.50 per share for this investment.
The initial close was scheduled for early in the fourth quarter of 1999.
However, in October 1999, another insurance company, XL Capital, Inc., submitted
a competing bid to acquire the shares of common stock in Capital Re.
Subsequently, ACE matched the competing bid with an offer composed of cash and
stock, whose exchange rate was increased from their initial offer. As of the
date of this report, the market value of the current offer is approximately
$14.40 per share and is partially dependent on the market value of ACE stock.
Upon closing, which is expected to occur in the first quarter of 2000, final
valuation will occur, and our financial investments business will record any
change in the market value of this investment to the income statement.
Earnings from our real estate and senior-living facilities business were
about the same compared to the same periods of 1998. In September 1999, earnings
include a $3.4 million after-tax, or $.02 per share write-down of certain
senior-living facilities related to the sale of these facilities as discussed
below. This write-down was offset by higher earnings from various other real
estate projects in 1999.
In August 1999, our senior-living facilities business announced that it
entered into an agreement to sell all but one of its senior-living facilities to
Sunrise Assisted Living, Inc. Under the terms of the agreement, Sunrise was to
acquire twelve of our existing senior-living facilities, three facilities under
construction, and several sites under development for $72.2 million in cash and
$16.0 million in debt assumption. We have been unable to reach agreement on
financing issues that subsequently arose, and the agreement was terminated in
November 1999. As a result, our real estate and senior-living facilities
business will now engage a third-party management company to assist in managing
its senior-living facilities portfolio including the three facilities now under
construction, which will be completed by our real estate and senior-living
facilities business in the first half of 2000.
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.
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.
Our current real estate strategy is to hold each real estate project until
we can realize a reasonable value for it. We evaluate strategies for all our
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.
28
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.
Under accounting rules, we are required to write down the value of a real
estate project to market value in either of two cases. The first is if we change
our intent about a project from an intent to hold to an intent to sell and the
market value of that project is below book value. The second is if the expected
cash flow from the project is less than the investment in the project.
- --------------------------------------------------------------------------------
Financial Condition
- -------------------
Cash Flows
- ----------
For the nine months ended September 30:
- ---------------------------------------
1999 1998
---- ----
(In millions)
Cash provided by (used in):
Operating Activities $ 483.5 $ 654.8
Investing Activities (441.8) (415.1)
Financing Activities (159.0) (187.2)
During the nine months ended September 30, 1999, we generated less cash from
operations compared to the same period in 1998 mostly because of changes in
working capital requirements.
During the nine months ended September 30, 1999, we used more cash for
investing activities compared to the same period in 1998 mostly because of the
following factors: our power marketing and trading business increased its
investment in Orion Power Holdings, Inc. by $97.7 million, our power projects
business increased its investment in power projects by $25.7 million, and BGE
increased its capital expenditures by $11.9 million. These increases are
partially offset by a $60.7 million investment for the purchase of a power
generation facility in Guatemala in 1998 by our power projects business. In
addition, our real estate and senior-living facilities business invested less in
1999 compared to the same period of 1998.
During the nine months ended September 30, 1999, we used less cash for
financing activities compared to the same period of 1998 mostly because we
redeemed less BGE preference stock and our net short-term borrowings were
higher. This was partially offset by an increase in the repayments of long-term
debt and a decrease in the issuances of long-term debt.
Security Ratings
- ----------------
Independent credit-rating agencies rate Constellation Energy and BGE's
fixed-income securities. The ratings indicate the agencies' assessment of each
company's ability to pay interest, distributions, dividends, and principal on
these securities. These ratings affect how much it will cost each company to
sell these securities. The better the rating, the lower the cost of the
securities to each company when they sell them. Constellation Energy and BGE's
securities ratings at the date of this report are:
Standard Moody's Duff & Phelps'
& Poors Investors Credit
Rating Group Service Rating Co.
------------- ---------- --------------
Constellation Energy
- --------------------
Unsecured Debt A- A3 A
BGE
- ---
Mortgage Bonds AA- A1 AA-
Unsecured Debt A A2 A+
Trust Originated
Preferred Securities
and Preference Stock A- "a2" A
Capital Resources
- -----------------
Our business requires a great deal of capital. Our actual consolidated
capital requirements for the nine months ended September 30, 1999, along with
estimated annual amounts for the years 1999 through 2001, are shown on page 30.
For the twelve months ended September 30, 1999, the ratio of earnings to fixed
charges for Constellation Energy was 2.68. The ratio of earnings to fixed
charges for BGE was 3.32 and the ratio of earnings to combined fixed charges and
preferred and preference dividend requirements for BGE was 3.00.
29
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.
Upon receipt of all regulatory approvals, on July 1, 2000, all of BGE's
generation assets will be moved to nonregulated subsidiaries of Constellation
Energy. The discussion and table for capital requirements below include these
generation assets as part of the utility business.
Nine Months Ended
September 30, Calendar Year Estimates
1999 1999 2000 2001
--------- ------- -- -------- -- --------
(In millions)
Utility Business Capital Requirements:
- --------------------------------------
Construction expenditures (excluding AFC)
Electric $ 176 $ 290 $327 $330
Gas 42 64 64 63
Common 20 27 25 24
-------- ------- ------- -------
Total construction expenditures 238 381 416 417
AFC 8 11 7 4
Nuclear fuel (uranium purchases and processing charges) 45 46 50 48
Deferred energy conservation expenditures 1 1 - -
Retirement of long-term debt and redemption of
preference stock 250 342 403 282
-------- ------- ------- -------
Total utility business capital requirements 542 781 876 751
-------- ------- ------- -------
Diversified Business Capital Requirements:
- ------------------------------------------
Investment requirements 140 140 766 697
Retirement of long-term debt 116 201 273 367
-------- ------- ------- -------
Total diversified business capital requirements 256 341 1,039 1,064
-------- ------- ------- -------
Total capital requirements $ 798 $1,122 $1,915 $1,815
======== ======= ======= =======
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 $40 million in 2000, and
o $66 million in 2001.
We estimate that during the two-year period 2002 through 2003, we will spend
an additional $150 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.
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.
30
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 $33 million in 1999,
o $60 million in 2000, and
o $52 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 September 30, 1999, our utility operations
provided about 92% 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.
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, 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
September 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
annual committed bank lines of credit and has $100 million in bank revolving
credit agreements. In addition, BGE has access to interim lines of credit as
required from time to time to support its outstanding commercial paper.
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, 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 $104
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, commercial paper issuances and
long-term debt financing by Constellation Energy and from time to time equity
contributions from Constellation Energy. BGE Home Products & Services may also
meet capital requirements through sales of receivables.
At September 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. In addition, Constellation Energy has access to interim lines of credit
as required from time to time to support its outstanding commercial paper. 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.
31
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 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 involved conducting an inventory of all systems and identifying
appropriate resources. We 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 included 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 included:
o our budget,
o schedules for Phase I and II, and
o our remediation approach - repair, upgrade, replace or retire.
32
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, provided a reliable estimate of our risks and costs.
Phase II included converting and testing all of our systems. Each system was
tested by those employees used in Phase I following formal guidelines developed
by the PMO. Each system or piece of equipment was then certified by a tester and
the PMO, following testing guidelines developed with the help of outside
consultants. We received an independent Year 2000 readiness review of our
processes and systems. Phase II also included identifying our major suppliers
and developing contingency plans. We have identified our mission critical
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
completing the readiness review of our non-mission critical suppliers through
surveys.
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 have addressed 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 drafted year
2000 operational preparedness plans and restoration scenarios and continues to
coordinate and develop these plans during the fourth quarter of 1999 in
cooperation with NERC. The NERC continues to perform monthly assessments of the
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 and data
communications.
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.
On September 8-9, 1999, we participated in the second NERC sponsored drill.
The focus of this drill was a simulation of the rollover to the year 2000 for
the electric utility industry. BGE expanded the drill to include all of its
business areas. The drill was successful as it demonstrated our understanding of
our Year 2000 Operational Contingency Plan and our ability to operate gas and
electric systems with limited voice and data communications.
Through the Electric Power Research Institute (EPRI), an industry-wide
effort was 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 assessed specific vendors' system problems and test
plans. These assessments have been shared by the industry as a whole to
facilitate year 2000 problem solving.
BGE 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 performed quarterly assessments of the gas utility
industry to communicate the readiness of its members for the year 2000.
33
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 and II.
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- September Remainder of
1997 1998 30, 1999 1999 2000
------ ---- -------- ------- ----
(In millions)
Total Cost $1.8 $18.9 $14.0 $7.7 $3.6 $46.0
Less: Capital
cost - 7.3 4.2 2.8 0.2 14.5
----- ------ ----- -------- ---- -------
O&M cost 1.8 11.6 9.8 4.9 3.4 31.5
Less:
non-incremental
O&M cost 1.8 4.6 4.1 2.9 1.9 15.3
----- ------ ----- -------- ---- -------
Incremental
O&M cost $ - $7.0 $5.7 $ 2.0 $1.5 $16.2
===== ====== ====== ======== ==== =======
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 have had a similar level of commitment of
resources during 1999.
Diversified Businesses
- ----------------------
Overview
- --------
Our diversified businesses have established year 2000 task forces to address
their year 2000 issues. As the assessments were completed, the businesses
developed 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.
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 project 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 are developing 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 on page 35.
However, if any of these scenarios actually occurred, the impact is not expected
to be material to our consolidated financial results.
34
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 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 all phases of their year 2000
projects.
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. This business completed the assessment and detailed analysis
phase and has substantially completed the testing, remediation, and
certification phase of its Year 2000 project.
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.
35
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.
Under the Restructuring Order, BGE will provide standard offer service to
customers at fixed rates over various time periods during the transition period,
and the electric fuel rate will be discontinued effective July 1, 2000.
Additionally, upon receipt of all regulatory approvals, BGE will transfer all of
its generating assets to nonregulated subsidiaries of Constellation Energy at
that time. As a result of these provisions of the Restructuring Order, BGE will
be subject to market risk associated with acquiring energy to provide standard
offer service, and Constellation Energy's nonregulated subsidiaries will be
subject to market risk associated with the sale of energy from their generating
assets. At this time, we cannot estimate the financial risks associated with
this transition. However, these financial risks could have a material impact on
our financial position or our results of operations.
36
PART II. OTHER INFORMATION
Item 1. Legal Proceedings
Asbestos
- --------
Since 1993, we have been involved in several actions concerning asbestos.
The actions are based upon the theory of "premises liability," alleging that we
knew of and exposed individuals to an asbestos hazard. The actions relate to two
types of claims.
The first type is direct claims by individuals exposed to asbestos. We
described these claims in BGE's Report on Form 8-K filed August 20, 1993. We are
involved in these claims with approximately 70 other defendants. Approximately
530 individuals that were never employees of BGE each claim $6 million in
damages ($2 million compensatory and $4 million punitive). These claims were
filed in the Circuit Court for Baltimore City, Maryland in the summer of 1993.
We do not know the specific facts necessary to estimate our potential liability
for these claims. The specific facts we do not know include:
o the identity of our facilities at which the plaintiffs allegedly worked
as contractors,
o the names of the plaintiff's employers, and
o the date on which the exposure allegedly occurred.
To date, 22 of these cases were settled 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
140 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.
Waste Disposal
- --------------
As previously reported in our 1998 Annual Report on Form 10-K in United
States v. Keystone Sanitation Company, et al., BGE and other defendants entered
into a settlement with the Environmental Protection Agency for an immaterial
amount in regard to contamination of the Keystone Sanitation Company landfill
Superfund site in Adams County, Pennsylvania in 1997. On September 10, 1999, the
U.S. District Court for the Middle District of PA approved the settlement,
ending BGE's involvement with the site.
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 implications of the Restructuring Order issued by the Maryland PSC,
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. 10(a) Constellation Energy Group, Inc. 1995 Long-Term Incentive Plan, as
amended and restated.
Exhibit No. 10(b) Constellation Energy Group, Inc. Nonqualified Deferred Compensation
Plan, as amended and restated.
Exhibit No. 10(c) Constellation Energy Group, Inc. Executive Benefits Plan, as amended
and restated.
Exhibit No. 10(d) Executive Annual Incentive Plan of Constellation Energy Group, Inc.
as amended and restated.
Exhibit No. 10(e) Summary of Severance Arrangement for a Named Executive Officer.
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 September 30, 1999:
Date Filed Items Reported
---------- --------------
July 19, 1999 Item 5. Other Events
Item 7. 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: November 12, 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
------
10(a) Constellation Energy Group, Inc. 1995 Long-Term Incentive
Plan, as amended and restated.
10(b) Constellation Energy Group, Inc. Nonqualified Deferred
Compensation Plan, as amended and restated.
10(c) Constellation Energy Group, Inc. Executive Benefits Plan,
as amended and restated.
10(d) Executive Annual Incentive Plan of Constellation Energy
Group, Inc. as amended and restated.
10(e) Summary of Severance Arrangement for a Named Executive
Officer.
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.
40