UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For The Quarterly Period Ended JUNE 30, 2000
Commission Exact name of registrant IRS Employer
File Number as specified in its charter Identification No.
- ----------- --------------------------- -----------------
1-12869 CONSTELLATION ENERGY GROUP, INC. 52-1964611
1-1910 BALTIMORE GAS AND ELECTRIC COMPANY 52-0280210
MARYLAND
-----------------------------------
(State of Incorporation)
250 W. PRATT STREET, BALTIMORE, MARYLAND 21201
--------------------- --------------------- -------
(Address of principal executive offices) (Zip Code)
410-234-5000
------------
(Registrants' telephone number, including area code)
NOT APPLICABLE
------------------------------
(Former name, former address
and former fiscal year, if changed since last report)
Indicate by check mark whether the registrants (1) have filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months, and (2) have been subject to such filing
requirements for the past 90 days.
Yes X No
----
Common Stock, without par value 149,731,716 shares outstanding of Constellation
Energy Group, Inc. on July 31, 2000.
TABLE OF CONTENTS
Page
Part I -- Financial Information
Item 1 -- Financial Statements
Constellation Energy Group, Inc. and Subsidiaries
Consolidated Statements of Income...................................................... 3
Consolidated Statements of Comprehensive Income........................................ 3
Consolidated Balance Sheets............................................................ 4
Consolidated Statements of Cash Flows.................................................. 6
Baltimore Gas and Electric Company and Subsidiaries
Consolidated Statements of Income...................................................... 7
Consolidated Statements of Comprehensive Income........................................ 7
Consolidated Balance Sheets............................................................ 8
Consolidated Statements of Cash Flows.................................................. 10
Notes to Consolidated Financial Statements............................................. 11
Item 2 -- Management's Discussion and Analysis of Financial Condition and
Results of Operations
Introduction........................................................................... 17
Strategy............................................................................... 18
Current Issues......................................................................... 19
Results of Operations.................................................................. 21
Financial Condition.................................................................... 31
Capital Resources...................................................................... 31
Other Matters.......................................................................... 34
Item 3 -- Quantitative and Qualitative Disclosures About Market Risk............................. 34
Part II -- Other Information
Item 1 -- Legal Proceedings...................................................................... 35
Item 4-- Submission of Matters to a Vote of Security Holders.................................... 36
Item 5 -- Other Information...................................................................... 37
Item 6 -- Exhibits and Reports on Form 8-K....................................................... 38
Signature........................................................................................ 39
2
CONSTELLATION ENERGY GROUP, INC. AND SUBSIDIARIES
PART I - FINANCIAL INFORMATION
Item 1 - Financial Statements
Consolidated Statements of Income (Unaudited)
Three Months Ended June 30, Six Months Ended June 30,
--------------------------- -------------------------
2000 1999 2000 1999
------------ ------------ ------------ -----------
(In Millions, Except Per-Share Amounts)
Revenues
Electric $ 565.3 $ 533.0 $ 1,089.7 $ 1,046.0
Gas 91.6 79.9 286.1 272.7
Nonregulated 211.5 245.6 484.8 523.2
------------ ------------ ------------ -----------
Total revenues 868.4 858.5 1,860.6 1,841.9
Operating Expenses
Electric fuel and purchased energy 119.5 120.0 238.1 241.2
Gas purchased for resale 40.8 33.0 143.7 135.1
Operations 138.9 135.2 273.2 270.5
Maintenance 54.4 53.6 99.5 102.4
Nonregulated - selling, general, and administrative 199.2 210.2 414.1 437.6
Depreciation and amortization 130.6 90.8 263.1 181.1
Taxes other than income taxes 51.1 51.8 112.3 112.1
------------ ------------ ------------ -----------
Total operating expenses 734.5 694.6 1,544.0 1,480.0
------------ ------------ ------------ -----------
Income From Operations 133.9 163.9 316.6 361.9
Other Income 1.0 5.2 6.0 4.5
------------ ------------ ------------ -----------
Income Before Fixed Charges and Income Taxes 134.9 169.1 322.6 366.4
Fixed Charges
Interest expense (net) 65.1 58.2 125.4 119.3
BGE preference stock dividends 3.3 3.4 6.6 6.9
------------ ------------ ------------ -----------
Total fixed charges 68.4 61.6 132.0 126.2
------------ ------------ ------------ -----------
Income Before Income Taxes 66.5 107.5 190.6 240.2
Income Taxes
Current 45.6 26.4 106.8 75.9
Deferred (16.6) 15.3 (23.7) 17.8
Investment tax credit adjustments (2.1) (2.2) (4.2) (4.3)
------------ ------------ ------------ -----------
Total income taxes 26.9 39.5 78.9 89.4
------------ ------------ ------------ -----------
Net Income $ 39.6 $ 68.0 $ 111.7 $ 150.8
============ ============ ============ ===========
Earnings Applicable to Common Stock $ 39.6 $ 68.0 $ 111.7 $ 150.8
============ ============ ============ ===========
Average Shares of Common Stock Outstanding 149.7 149.6 149.6 149.6
Earnings Per Common Share and
Earnings Per Common Share - Assuming Dilution $0.26 $0.45 $0.75 $1.01
Dividends Declared Per Common Share $0.42 $0.42 $0.84 $0.84
Consolidated Statements of Comprehensive Income (Unaudited)
Three Months Ended June 30, Six Months Ended June 30,
--------------------------- -------------------------
2000 1999 2000 1999
------------ ------------ ------------ -----------
(In Millions)
Net Income $ 39.6 $ 68.0 $ 111.7 $ 150.8
Other comprehensive income (loss), net of taxes 11.1 (8.3) 24.1 (11.5)
------------ ------------ ------------ -----------
Comprehensive Income $ 50.7 $ 59.7 $ 135.8 $ 139.3
============ ============ ============ ===========
See Notes to Consolidated Financial Statements.
Certain prior period amounts have been reclassified to conform with the current
period's presentation.
3
CONSTELLATION ENERGY GROUP, INC. AND SUBSIDIARIES
PART I - FINANCIAL INFORMATION (CONTINUED)
Item 1 - Financial Statements
Consolidated Balance Sheets
June 30, December 31,
2000* 1999
------------- -------------
(In Millions)
Assets
Current Assets
Cash and cash equivalents $ 146.4 $ 92.7
Accounts receivable (net of allowance for uncollectibles
of $27.9 and $36.6 respectively) 559.7 578.5
Trading securities 156.8 136.5
Assets from energy trading activities 1,079.3 312.1
Fuel stocks 84.7 94.9
Materials and supplies 138.2 149.1
Prepaid taxes other than income taxes 8.8 72.4
Other 62.3 54.0
------------- -------------
Total current assets 2,236.2 1,490.2
Investments and Other Assets
Real estate projects and investments 298.9 310.1
Power projects 926.2 785.4
Financial investments 167.8 145.4
Nuclear decommissioning trust fund 230.3 217.9
Net pension asset 99.3 99.5
Other 533.4 422.9
------------- -------------
Total investments and other assets 2,255.9 1,981.2
Utility Plant
Plant in service
Electric 7,157.4 7,088.6
Gas 975.2 962.0
Common 557.8 569.5
------------- -------------
Total plant in service 8,690.4 8,620.1
Accumulated depreciation (3,572.2) (3,466.1)
------------- -------------
Net plant in service 5,118.2 5,154.0
Construction work in progress 277.7 222.3
Nuclear fuel (net of amortization) 150.7 133.8
Plant held for future use 12.9 13.0
------------- -------------
Net utility plant 5,559.5 5,523.1
Deferred Charges
Regulatory assets (net) 522.9 637.4
Other 61.9 51.9
------------- -------------
Total deferred charges 584.8 689.3
------------- -------------
Total Assets $ 10,636.4 $ 9,683.8
============= =============
* Unaudited
See Notes to Consolidated Financial Statements.
4
CONSTELLATION ENERGY GROUP, INC. AND SUBSIDIARIES
PART I - FINANCIAL INFORMATION (CONTINUED)
Item 1 - Financial Statements
Consolidated Balance Sheets
June 30, December 31,
2000* 1999
------------- -------------
(In Millions)
Liabilities and Capitalization
Current Liabilities
Short-term borrowings $ 214.8 $ 371.5
Current portion of long-term debt 883.5 808.3
Accounts payable 301.7 365.1
Customer deposits 43.0 40.6
Liabilities from energy trading activities 834.8 163.8
Dividends declared 66.2 66.1
Accrued taxes 37.3 19.2
Accrued interest 59.6 55.3
Accrued vacation costs 36.6 35.3
Other 50.6 78.2
------------- -------------
Total current liabilities 2,528.1 2,003.4
Deferred Credits and Other Liabilities
Deferred income taxes 1,275.5 1,288.8
Postretirement and postemployment benefits 254.9 269.8
Deferred investment tax credits 105.4 109.6
Decommissioning of federal uranium enrichment facilities 27.2 27.2
Other 291.0 226.6
------------- -------------
Total deferred credits and other liabilities 1,954.0 1,922.0
Long-term Debt
First refunding mortgage bonds of BGE 1,321.7 1,321.7
Other long-term debt of BGE 1,028.4 1,135.8
Company obligated mandatorily redeemable trust preferred
securities of subsidiary trust holding solely 7.16% debentures
of BGE due June 30, 2038 250.0 250.0
Long-term debt of nonregulated businesses 1,246.6 686.8
Unamortized discount and premium (9.8) (10.6)
Current portion of long-term debt (883.5) (808.3)
------------- -------------
Total long-term debt 2,953.4 2,575.4
BGE Preference Stock Not Subject to Mandatory Redemption 190.0 190.0
Common Shareholders' Equity
Common stock 1,501.8 1,494.0
Retained earnings 1,485.1 1,499.1
Accumulated other comprehensive income (loss) 24.0 (0.1)
------------- -------------
Total common shareholders' equity 3,010.9 2,993.0
------------- -------------
Total capitalization 6,154.3 5,758.4
------------- -------------
Total Liabilities and Capitalization $ 10,636.4 $ 9,683.8
============= =============
* Unaudited
See Notes to Consolidated Financial Statements.
5
CONSTELLATION ENERGY GROUP, INC. AND SUBSIDIARIES
PART I - FINANCIAL INFORMATION (CONTINUED)
Item 1 - Financial Statements
Consolidated Statements of Cash Flows (Unaudited)
Six Months Ended June 30,
---------------------------
2000 1999
------------ ------------
Cash Flows From Operating Activities
Net income $ 111.7 $ 150.8
Adjustments to reconcile to net cash provided by operating activities
Depreciation and amortization 288.2 208.4
Deferred income taxes (23.7) 17.8
Investment tax credit adjustments (4.2) (4.3)
Deferred fuel costs 9.8 7.1
Accrued pension and postemployment benefits 12.1 28.7
Gain on sale of subsidiaries (13.3) -
Write-down of financial investment - 5.5
Equity in earnings of affiliates and joint ventures (net) 5.3 26.2
Changes in assets from energy trading activities (767.2) (141.2)
Changes in liabilities from energy trading activities 671.0 37.4
Changes in other current assets 59.8 (45.3)
Changes in other current liabilities (1.3) 89.3
Other (5.9) (10.2)
------------ ------------
Net cash provided by operating activities 342.3 370.2
------------ ------------
Cash Flows From Investing Activities
Utility construction and other capital expenditures (218.1) (186.0)
Contributions to nuclear decommissioning trust fund (8.8) (8.8)
Purchases of marketable equity securities (2.4) (12.4)
Sales of marketable equity securities 14.4 9.8
Other financial investments 8.7 8.5
Real estate projects and investments 9.0 40.7
Power projects (147.0) (31.8)
Investment in Orion Power Holdings, Inc. (101.5) -
Other (12.4) (15.5)
------------ ------------
Net cash used in investing activities (458.1) (195.5)
------------ ------------
Cash Flows From Financing Activities
Proceeds from issuance of
Short-term borrowings 4,852.6 1,029.3
Long-term debt 800.1 127.5
Common stock 6.0 9.6
Repayments of short-term borrowings (5,009.3) (920.0)
Reacquisitions of long-term debt (347.7) (360.5)
Common stock dividends paid (125.6) (125.5)
Other (6.6) (5.4)
------------ ------------
Net cash provided by (used in) financing activities 169.5 (245.0)
------------ ------------
Net Increase (Decrease) in Cash and Cash Equivalents 53.7 (70.3)
Cash and Cash Equivalents at Beginning of Period 92.7 173.7
------------ ------------
Cash and Cash Equivalents at End of Period $ 146.4 $ 103.4
============ ============
Other Cash Flow Information:
Interest paid (net of amounts capitalized) $ 131.5 $ 120.4
Income taxes paid $ 110.9 $ 101.0
See Notes to Consolidated Financial Statements.
Certain prior period amounts have been reclassified to conform with the current
period's presentation.
6
BALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARIES
PART I - FINANCIAL INFORMATION
Item 1 - Financial Statements
Consolidated Statements of Income (Unaudited)
Three Months Ended June 30, Six Months Ended June 30,
--------------------------- -------------------------
2000 1999 2000 1999
------------ ------------ ----------- ------------
(In Millions)
Revenues
Electric $ 565.4 $ 533.1 $ 1,090.0 $ 1,046.1
Gas 92.7 81.6 287.8 274.4
Nonregulated 1.3 67.3 2.3 345.0
------------ ------------ ----------- ------------
Total revenues 659.4 682.0 1,380.1 1,665.5
Operating Expenses
Electric fuel and purchased energy 124.7 124.2 244.1 245.4
Gas purchased for resale 40.9 33.0 143.8 135.1
Operations 137.3 134.9 270.2 270.2
Maintenance 54.6 52.9 99.3 101.8
Nonregulated - selling, general, and administrative 1.0 56.7 1.7 284.2
Depreciation and amortization 123.7 88.3 249.8 178.5
Taxes other than income taxes 50.5 51.1 110.6 111.4
------------ ------------ ----------- ------------
Total operating expenses 532.7 541.1 1,119.5 1,326.6
------------ ------------ ----------- ------------
Income From Operations 126.7 140.9 260.6 338.9
Other Income
Allowance for equity funds used during construction 0.8 2.0 1.6 3.7
Equity in earnings of Safe Harbor Water Power Corporation 1.2 1.3 2.4 2.6
Net other income (expense) 0.4 0.7 1.7 (3.0)
------------ ------------ ----------- ------------
Total other income 2.4 4.0 5.7 3.3
------------ ------------ ----------- ------------
Income Before Fixed Charges and Income Taxes 129.1 144.9 266.3 342.2
Fixed Charges
Interest expense (net) 48.3 51.8 97.0 114.1
Capitalized interest - (0.1) - (0.4)
Allowance for borrowed funds used during construction (1.4) (1.1) (2.6) (2.0)
------------ ------------ ----------- ------------
Total fixed charges 46.9 50.6 94.4 111.7
------------ ------------ ----------- ------------
Income Before Income Taxes 82.2 94.3 171.9 230.5
Income Taxes
Current 44.0 39.0 101.8 88.6
Deferred (12.2) (3.8) (32.4) (1.3)
Investment tax credit adjustments (2.0) (2.1) (4.1) (4.3)
------------ ------------ ----------- ------------
Total income taxes 29.8 33.1 65.3 83.0
------------ ------------ ----------- ------------
Net Income 52.4 61.2 106.6 147.5
Preference Stock Dividends 3.3 3.4 6.6 6.9
------------ ------------ ----------- ------------
Earnings Applicable to Common Stock $ 49.1 $ 57.8 $ 100.0 $ 140.6
============ ============ =========== ============
Consolidated Statements of Comprehensive Income (Unaudited)
Three Months Ended June 30, Six Months Ended June 30,
--------------------------- -------------------------
2000 1999 2000 1999
------------ ------------ ----------- ------------
(In Millions)
Net Income $ 52.4 $ 61.2 $ 106.6 $ 147.5
Other comprehensive loss, net of taxes - (0.2) - (3.4)
------------ ------------ ----------- ------------
Comprehensive Income $ 52.4 $ 61.0 $ 106.6 $ 144.1
============ ============ =========== ============
See Notes to Consolidated Financial Statements.
Certain prior period amounts have been reclassified to conform with the current
period's presentation.
7
BALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARIES
PART I - FINANCIAL INFORMATION (CONTINUED)
Item 1 - Financial Statements
Consolidated Balance Sheets
June 30, December 31,
2000* 1999
-------------- ---------------
(In Millions)
Assets
Current Assets
Cash and cash equivalents $ 18.7 $ 23.5
Accounts receivable (net of allowance for uncollectibles
of $13.9 and $13.0 respectively) 335.7 316.1
Fuel stocks 84.7 94.9
Materials and supplies 126.5 139.1
Prepaid taxes other than income taxes 8.8 72.4
Other 33.6 9.0
-------------- ---------------
Total current assets 608.0 655.0
Investments and Other Assets
Nuclear decommissioning trust fund 230.3 217.9
Net pension asset 103.1 99.8
Safe Harbor Water Power Corporation 34.5 34.5
Other 65.9 61.6
-------------- ---------------
Total investments and other assets 433.8 413.8
Utility Plant
Plant in service
Electric 7,157.4 7,088.6
Gas 975.2 962.0
Common 557.8 569.5
-------------- ---------------
Total plant in service 8,690.4 8,620.1
Accumulated depreciation (3,572.2) (3,466.1)
-------------- ---------------
Net plant in service 5,118.2 5,154.0
Construction work in progress 277.7 222.3
Nuclear fuel (net of amortization) 150.7 133.8
Plant held for future use 12.9 13.0
-------------- ---------------
Net utility plant 5,559.5 5,523.1
Deferred Charges
Regulatory assets (net) 522.9 637.4
Other 41.6 43.3
-------------- ---------------
Total deferred charges 564.5 680.7
-------------- ---------------
Total Assets $ 7,165.8 $ 7,272.6
============== ===============
* Unaudited
See Notes to Consolidated Financial Statements.
8
BALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARIES
PART I - FINANCIAL INFORMATION (CONTINUED)
Item 1 - Financial Statements
Consolidated Balance Sheets
June 30, December 31,
2000* 1999
-------------- ---------------
(In Millions)
Liabilities and Capitalization
Current Liabilities
Short-term borrowings $ 199.3 $ 129.0
Current portion of long-term debt 503.4 523.9
Accounts payable 215.0 222.8
Customer deposits 43.0 40.6
Dividends declared 3.3 3.3
Accrued taxes 20.9 9.2
Accrued interest 46.0 48.2
Accrued vacation costs 37.4 35.7
Other 37.1 65.8
-------------- ---------------
Total current liabilities 1,105.4 1,078.5
Deferred Credits and Other Liabilities
Deferred income taxes 997.4 1,032.0
Postretirement and postemployment benefits 247.7 231.0
Deferred investment tax credits 105.4 109.6
Decommissioning of federal uranium enrichment facilities 27.2 27.2
Other 41.1 42.9
-------------- ---------------
Total deferred credits and other liabilities 1,418.8 1,442.7
Long-term Debt
First refunding mortgage bonds of BGE 1,321.7 1,321.7
Other long-term debt of BGE 1,028.4 1,135.8
Company obligated mandatorily redeemable trust preferred
securities of subsidiary trust holding solely 7.16% debentures
of BGE due June 30, 2038 250.0 250.0
Long-term debt of nonregulated businesses 33.0 33.0
Unamortized discount and premium (9.6) (10.6)
Current portion of long-term debt (503.4) (523.9)
-------------- ---------------
Total long-term debt 2,120.1 2,206.0
Preference Stock Not Subject to Mandatory Redemption 190.0 190.0
Common Shareholder's Equity
Common stock 1,495.8 1,494.0
Retained earnings 835.7 861.4
-------------- ---------------
Total common shareholder's equity 2,331.5 2,355.4
-------------- ---------------
Total capitalization 4,641.6 4,751.4
-------------- ---------------
Total Liabilities and Capitalization $ 7,165.8 $ 7,272.6
============== ===============
* Unaudited
See Notes to Consolidated Financial Statements.
9
BALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARIES
PART I - FINANCIAL INFORMATION (CONTINUED)
Item 1 - Financial Statements
Consolidated Statements of Cash Flows (Unaudited)
Six Months Ended June 30,
--------------------------
2000 1999
----------- -----------
(In Millions)
Cash Flows From Operating Activities
Net income $ 106.6 $ 147.5
Adjustments to reconcile to net cash provided by operating activities
Depreciation and amortization 272.9 204.4
Deferred income taxes (32.4) (1.3)
Investment tax credit adjustments (4.1) (4.3)
Deferred fuel costs 9.8 7.1
Accrued pension and postemployment benefits 12.0 28.6
Allowance for equity funds used during construction (1.6) (3.7)
Equity in earnings of affiliates and joint ventures (net) - 29.1
Changes in assets from energy trading activities - (120.1)
Changes in liabilities from energy trading activities - 76.3
Changes in other current assets 42.5 65.4
Changes in other current liabilities (22.5) (14.1)
Other 8.8 (0.6)
----------- -----------
Net cash provided by operating activities 392.0 414.3
----------- -----------
Cash Flows From Investing Activities
Utility construction expenditures (including AFC) (178.3) (166.8)
Allowance for equity funds used during construction 1.6 3.7
Nuclear fuel expenditures (39.5) (18.5)
Deferred energy conservation expenditures (0.3) (0.7)
Contributions to nuclear decommissioning trust fund (8.8) (8.8)
Purchases of marketable equity securities - (9.2)
Sales of marketable equity securities - 6.0
Other financial investments - 6.7
Real estate projects and investments - 22.0
Power projects - (17.9)
Other (3.9) (12.4)
----------- -----------
Net cash used in investing activities (229.2) (195.9)
----------- -----------
Cash Flows From Financing Activities
Proceeds from issuance of
Short-term borrowings 2,286.8 1,029.3
Long-term debt - 107.6
Common stock - 9.6
Repayments of short-term borrowings (2,216.5) (920.0)
Reacquisition of long-term debt (107.5) (343.9)
Preference stock dividends paid (6.6) (6.9)
Distributions to Constellation Energy (125.6) (253.7)
Other 1.8 (0.7)
----------- -----------
Net cash used in financing activities (167.6) (378.7)
----------- -----------
Net Decrease in Cash and Cash Equivalents (4.8) (160.3)
Cash and Cash Equivalents at Beginning of Period 23.5 173.7
----------- -----------
Cash and Cash Equivalents at End of Period $ 18.7 $ 13.4
=========== ===========
Other Cash Flow Information:
Interest paid (net of amounts capitalized) $ 94.2 $ 107.4
Income taxes paid $ 113.1 $ 99.3
See Notes to Consolidated Financial Statements.
10
Notes to Consolidated Financial Statements
- ------------------------------------------
Weather conditions can have a great impact on our results for interim periods.
This means that results for interim periods do not necessarily represent results
to be expected for the year.
Our interim financial statements on the previous pages reflect all adjustments
that Management believes are necessary for the fair presentation of the
financial position and results of operations for the interim periods presented.
These adjustments are of a normal recurring nature.
Holding Company Formation
- -------------------------
On April 30, 1999, Constellation Energy (R) Group, Inc. (Constellation Energy)
became the holding company for Baltimore Gas and Electric Company (BGE(R)) and
Constellation(R) Enterprises, Inc. Constellation Enterprises was previously
owned by BGE. BGE's outstanding common stock automatically became shares of
common stock of Constellation Energy. BGE's debt securities, obligated
mandatorily redeemable trust preferred securities, and preference stock remain
securities of BGE.
Basis of Presentation
- ---------------------
This Quarterly Report on Form 10-Q is a combined report of Constellation Energy
and BGE. The consolidated financial statements of Constellation Energy include
the accounts of Constellation Energy, BGE and its subsidiaries, Constellation
Enterprises, Inc. and its subsidiaries, and Constellation Nuclear, LLC and its
subsidiaries. The consolidated financial statements of BGE include the accounts
of BGE, District Chilled Water General Partnership (ComfortLink), and BGE
Capital Trust I. As Constellation Enterprises and its subsidiaries were
subsidiaries of BGE prior to April 30, 1999, they are included in the
consolidated financial statements of BGE through that date.
References in this report to "we" and "our" are to Constellation Energy and its
subsidiaries, collectively. Reference in this report to the "utility business"
is to BGE.
Deregulation of Electric Generation
- -----------------------------------
On April 8, 1999, Maryland enacted legislation authorizing customer choice and
competition among electric suppliers. In addition, on November 10, 1999, the
Maryland Public Service Commission (Maryland PSC) issued a Restructuring Order
that resolved the major issues surrounding electric restructuring. Effective
July 1, 2000, the state of Maryland implemented customer choice for electric
suppliers. We discuss the implications of customer choice and the Restructuring
Order further in Management's Discussion and Analysis beginning on page 17.
Please also refer to the Legal Proceedings section on page 35 for a discussion
regarding appeals of the Restructuring Order.
Information by Operating Segment
- --------------------------------
In 1999, we reported three operating segments -- Electric, Gas, and Energy
Services. In response to the deregulation of electric generation, we realigned
our organization and combined our wholesale power marketing business with our
domestic plant development and operations to form a merchant energy business.
In 2000, we revised our operating segments to reflect the realignments of our
organization. Our new reportable operating segments are -- Regulated Electric,
Regulated Gas, and Domestic Wholesale Energy:
o Our regulated electric business generates, purchases, and sells electricity
in a regulated environment,
o Our regulated gas business purchases, transports, and sells natural gas in
a regulated environment, and
o Our nonregulated domestic wholesale energy business:
- develops, owns, and operates domestic power
projects,
- provides power marketing and risk management
services, and
- provides nuclear consulting services.
11
We have restated certain prior period information for comparative purposes based
on our new reportable operating segments.
The financial results of the electric generation portion of our business are
included in our regulated electric segment. However, after June 30, 2000, we
will include the financial results of electric generation in the domestic
wholesale energy segment.
Our remaining nonregulated businesses:
o develop, own, and operate international power projects,
o provide energy products and services,
o sell and service electric and gas appliances, and heating and air
conditioning systems, engage in home improvements, and sell natural gas
through mass marketing efforts,
o provide cooling services,
o engage in financial investments, and
o develop, own and manage real estate and senior-living facilities.
Domestic
Regulated Regulated Wholesale Other Unallocated
Electric Gas Energy Nonregulated Corporate
Business Business Business Businesses Items (a) Eliminations Consolidated
------------ ------------ ------------- --------------- -------------- ------------- ---------------
(in millions)
For the three months ended June 30,
2000
- ----
Unaffiliated revenues $565.3 $91.6 $81.4 $130.1 $ - $ - $868.4
Intersegment revenues 0.1 1.1 80.2 11.5 - (92.9) -
---------- ------------- ------------- --------------- -------------- ------------- ---------------
Total revenues 565.4 92.7 161.6 141.6 - (92.9) 868.4
Net income (loss) (b) 47.0 2.3 50.1 (9.7) - (50.1) 39.6
1999
- ----
Unaffiliated revenues $533.0 $79.9 $70.4 $175.2 $ - $ - $858.5
Intersegment revenues 0.1 2.4 0.5 10.9 - (13.9) -
---------- ------------- ------------- --------------- -------------- ------------- ---------------
Total revenues 533.1 82.3 70.9 186.1 - (13.9) 858.5
Net income (loss) (c) 54.7 0.6 17.3 (3.5) (0.8) (0.3) 68.0
For the six months ended June 30,
2000
- ----
Unaffiliated revenues $1,089.7 $286.1 $172.3 $312.5 $ - $ - $1,860.6
Intersegment revenues 0.3 1.7 80.2 18.2 - (100.4) -
---------- ------------- ------------- --------------- -------------- ------------- ---------------
Total revenues 1,090.0 287.8 252.5 330.7 - (100.4) 1,860.6
Net income (loss) (b) 77.8 22.6 69.3 (7.9) - (50.1) 111.7
1999
- ----
Unaffiliated revenues $1,046.0 $272.7 $126.6 $396.6 $ - $ - $1,841.9
Intersegment revenues 0.5 4.5 0.5 11.5 - (17.0) -
---------- ------------- ------------- --------------- -------------- ------------- ---------------
Total revenues 1,046.5 277.2 127.1 408.1 - (17.0) 1,841.9
Net income (loss) (c) 101.1 22.2 31.3 (3.0) (0.8) - 150.8
At June 30, 2000
- -----------------
Segment assets $6,195.7 $923.6 $2,386.3 $1,284.6 $92.1 $(245.9) $10,636.4
At December 31, 1999
- --------------------
Segment assets $6,312.6 $915.3 $1,206.1 $1,226.7 $37.0 $ (13.9) $9,683.8
12
(a) We do not allocate certain items presented in the table for Constellation
Energy Group and a holding company for our nonregulated businesses.
(b) Our electric business recorded expenses of $2.8 million for the quarter
ended June 30, 2000 and $7.0 million for the six-months ended June 30, 2000
related to employees that elected to participate in a Targeted Voluntary
Special Early Retirement Program. In addition, our domestic wholesale
energy business recorded a $15.0 million deregulation transition cost
incurred by our power marketing business. We discuss these further in the
Overview section of Management's Discussion and Analysis.
(c) Our other nonregulated businesses recorded a $3.6 million write-down of
their investment in Capital Re stock to reflect the market value of this
investment as discussed in the Nonregulated Businesses section of
Management's Discussion and Analysis.
Financing Activity
- ------------------
Constellation Energy
- --------------------
As discussed on page 11, effective April 30, 1999, BGE's outstanding common
stock automatically became shares of common stock of Constellation Energy.
During the period from January 1, 2000 through the date of this report, we
issued a total of 475,300 shares of common stock, without par value, under our
Continuous Offering Program for Stock. Net proceeds were about $16.8 million.
Constellation Energy issued the following medium-term notes during the period
from January 1, 2000 through the date of this report:
Date Net
Principal Issued Proceeds
----------------------------
(In millions)
7 7/8% Notes due 2005 $300 4/00 $297.5
Floating Rate Notes due 2003 200 4/00 199.3
Extendible Notes due 2010 300 6/00 299.6
In June 2000, Constellation Energy arranged two revolving credit agreements
totaling $565 million to support our commercial paper program and for other
working capital purposes. Of this amount, $376.5 million is for short-term
financial needs and $188.5 million, which expires in three years, is for short
and long-term financial needs, including letters of credit. As of the date of
this report, letters of credit totaling $40.9 million were issued under this
facility. Also, letters of credit totaling $131 million were issued under other
credit facilities.
Constellation Energy has issued guarantees in an amount up to $626.8 million
related to credit facilities and contractual performance of certain of its
nonregulated subsidiaries. However, the actual subsidiary liabilities related to
these guarantees totaled $408.8 million at June 30, 2000.
In the future, Constellation Energy may purchase some of its long-term debt in
the market. This will depend on market conditions and Constellation Energy's
capital structure.
BGE and Nonregulated Businesses
- -------------------------------
In June 2000, BGE arranged a $25 million long-term revolving credit agreement to
support its commercial paper program and for other working capital purposes.
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.
Please refer to the Funding for Capital Requirements section of Management's
Discussion and Analysis on page 33 for additional information about the debt of
BGE and our nonregulated businesses.
Stock Option Program
- --------------------
In May 2000, our Board of Directors approved the issuance of non-qualified stock
options to officers and key employees as permitted under existing incentive
plans. Under the plans, the options are granted at prices not less than the
market value of the stock at the date of grant, become exercisable ratably over
a three-year period beginning one-year from the date of grant, and expire ten
years from the date of grant. During the second quarter, we granted 2,313,000
stock options at an exercise price of $34.25.
As permitted by SFAS No. 123, Accounting for Stock-Based Compensation, we
measure our stock-based compensation in accordance with Accounting Principles
Board Opinion No. 25, Accounting for Stock Issued to Employees, and related
interpretations. Under this standard, compensation expense is measured as the
difference between the market value of our common stock and the exercise price
of the options on the grant date. Accordingly, no compensation expense was
recorded for the stock options granted in 2000.
13
Commitments
- -----------
Some of our nonregulated businesses have committed to contribute additional
capital and to make additional loans to some affiliates, joint ventures, and
partnerships in which they have an interest. At the date of this report, the
total amount of investment requirements committed to by our nonregulated
businesses was $219.2 million. This amount includes $19.5 million for our
domestic wholesale energy business' remaining commitment to Orion Power
Holdings, Inc. To date, our domestic wholesale energy business has funded $205.5
million in equity to Orion.
Environmental Matters
- ---------------------
Clean Air
- ---------
The Clean Air Act of 1990 contains two titles designed to reduce emissions of
sulfur dioxide and nitrogen oxide (NOx) from electric generating stations -
Title IV and Title I.
Title IV addresses emissions of sulfur dioxide. Compliance is required in two
phases:
o Phase I became effective January 1, 1995. We met the requirements of this
phase by installing flue gas desulfurization systems, switching fuels, and
retiring some units.
o Phase II became effective January 1, 2000. We met the compliance
requirements through a combination of switching fuels and allowance trading.
We will meet the ongoing compliance requirements through a combination of
switching fuels and allowance trading.
Title I addresses emissions of NOx. The Maryland Department of the Environment
(MDE) issued regulations, effective October 18, 1999, which required up to 65%
NOx emissions reductions by May 1, 2000. We entered into a settlement agreement
with the MDE since we could not meet this deadline. Under the terms of the
settlement agreement, BGE will install emissions reduction equipment at two
sites by May 2002. In the meantime, we are taking steps to control NOx emissions
at our generating plants.
The Environmental Protection Agency (EPA) issued a final rule in September 1998
that required up to 85% NOx emissions reduction by 22 states including Maryland
and Pennsylvania. Maryland expects to meet the requirements of the rule by 2003.
The emissions reduction equipment installations discussed above will allow us to
meet these requirements.
We currently estimate that the controls needed at our generating plants to meet
the MDE's 65% NOx emission reduction requirements will cost approximately $135
million. Through the date of this report, we have spent approximately $68
million to meet the 65% reduction requirements. We estimate the additional cost
for the EPA's 85% reduction requirements to be approximately $35 million by the
end of 2002.
In July 1997, the EPA published new National Ambient Air Quality Standards for
very fine particulates and revised standards for ozone attainment. In 1999,
these new standards were successfully challenged in court. The EPA appealed the
1999 court rulings to the Supreme Court. In May 2000, the Supreme Court decided
to hear the EPA's appeal. While these standards may require increased controls
at our fossil generating plants in the future, implementation, if required,
would be delayed for several years. We cannot estimate the cost of these
increased controls at this time because the states, including Maryland and
Pennsylvania, still need to determine what reductions in pollutants will be
necessary to meet the EPA standards.
Waste Disposal
- --------------
The EPA and several state agencies have notified us that we are considered a
potentially responsible party with respect to the cleanup of certain
environmentally contaminated sites owned and operated by others. We cannot
estimate the cleanup costs for all of these sites.
We can, however, estimate that our current 15.43% share of the reasonably
possible cleanup costs at one of these sites, Metal Bank of America, a metal
reclaimer in Philadelphia, could be as much as $4.9 million higher than amounts
we have recorded as a liability on our Consolidated Balance Sheets. This
estimate is based on a Record of Decision issued by the EPA.
On July 12, 1999, the EPA notified us, along with nineteen other entities, that
we may be a potentially responsible party at the 68th Street Dump/Industrial
Enterprises Site, also known as the Robb Tyler Dump located in Baltimore,
Maryland. The EPA indicated that it is proceeding with plans to conduct a
remedial investigation and feasibility study. This site was proposed for listing
as a federal Superfund site in January 1999, but the listing has not been
finalized. Although our potential liability cannot be estimated, we do not
expect such liability to be material based on our records showing that we did
not send waste to the site.
14
Also, we are coordinating investigation of several sites where gas was
manufactured in the past. The investigation of these sites includes reviewing
possible actions to remove coal tar. In late December 1996, we signed a consent
order with the MDE that requires us to implement remedial action plans for
contamination at and around the Spring Gardens site, located in Baltimore,
Maryland. We submitted the required remedial action plans and they were approved
by the MDE. Based on the remedial action plans, the costs we consider to be
probable to remedy the contamination are estimated to total $47 million. We have
recorded these costs as a liability on our Consolidated Balance Sheets and have
deferred these costs, net of accumulated amortization and amounts we recovered
from insurance companies, as a regulatory asset. We discuss this further in Note
5 of our 1999 Annual Report on Form 10-K. Through the date of this report, we
have spent approximately $35 million for remediation at this site.
We are also required by accounting rules to disclose additional costs we
consider to be less likely than probable, but still "reasonably possible" of
being incurred at these sites. Because of the results of studies at these sites,
it is reasonably possible that these additional costs could exceed the amount we
recognized by approximately $14 million.
We do not expect the cleanup costs of the remaining sites to have a material
effect on our financial results.
Our potential environmental liabilities and pending environmental actions are
described further in our 1999 Annual Report on Form 10-K in Item 1. Business -
Environmental Matters.
Nuclear Insurance
- -----------------
If there were an accident or an extended outage at either unit of the Calvert
Cliffs Nuclear Power Plant (Calvert Cliffs), it could have a substantial adverse
financial effect on us. The primary contingencies that would result from an
incident at Calvert Cliffs could include:
o physical damage to the plant,
o recoverability of replacement power costs, and
o our liability to third parties for property damage and bodily injury.
We have insurance policies that cover these contingencies, but the policies have
certain industry standard exclusions. Furthermore, the costs that could result
from a covered major accident or a covered extended outage at either of the
Calvert Cliffs units could exceed our insurance coverage limits.
Insurance for Calvert Cliffs and Third Party Claims
- ---------------------------------------------------
For physical damage to Calvert Cliffs, we have $2.75 billion of property
insurance from an industry mutual insurance company. If an outage at either of
the two units at Calvert Cliffs is caused by an insured physical damage loss and
lasts more than 12 weeks, we have insurance coverage for replacement power costs
up to $490.0 million per unit, provided by an industry mutual insurance company.
This amount can be reduced by up to $98.0 million per unit if an outage at both
units of the plant is caused by a single insured physical damage loss. If
accidents at any insured plants cause a shortfall of funds at the industry
mutual insurance company, all policyholders could be assessed, with our share
being up to $15.4 million.
In addition we, as well as others, could be charged for a portion of any third
party claims associated with a nuclear incident at any commercial nuclear power
plant in the country. At the date of this report, the limit for third party
claims from a nuclear incident is $9.54 billion under the provisions of the
Price Anderson Act. If third party claims exceed $200 million (the amount of
primary insurance), our share of the total liability for third party claims
could be up to $176.2 million per incident. That amount would be payable at a
rate of $20 million per year.
Insurance for Worker Radiation Claims
- -------------------------------------
As an operator of a commercial nuclear power plant in the United States, we are
required to purchase insurance to cover radiation injury claims of certain
nuclear workers. On January 1, 1998, a new insurance policy became effective for
all operators requiring coverage for current operations. Waiving the right to
make additional claims under the old policy was a condition for acceptance under
the new policy. We describe both the old and new policies below.
o Nuclear worker claims reported on or after January 1, 1998 are covered by a
new insurance policy with an annual industry aggregate limit of $200 million
for radiation injury claims against all those insured by this policy.
o All nuclear worker claims reported prior to January 1, 1998 are still covered
by the old insurance policies. Insureds under the old policies, with no
current operations, are not required to purchase the new policy described
above, and may still make claims against the old policies for the next eight
years. If radiation injury claims under these old policies exceed the policy
reserves, all policyholders could be assessed, with our share being up to
$6.3 million.
15
If claims under these polices exceed the coverage limits, the provisions of the
Price Anderson Act (discussed in this section) would apply.
Recoverability of Electric Fuel Costs
- -------------------------------------
Under the terms of the Restructuring Order, BGE's electric fuel rate clause was
discontinued effective July 1, 2000. Any accumulated difference between our
actual costs of fuel and energy and the amounts collected from customers under
the electric fuel rate clause through June 30, 2000 would be collected from our
customers within a twelve month period as determined by the Maryland PSC. At
June 30, 2000, the accumulated difference was $54.6 million.
We discuss the Maryland PSC's process for evaluating the recoverability of
electric fuel costs in Note 10 of our 1999 Annual Report on Form 10-K.
California Power Purchase Agreements
- ------------------------------------
Constellation Power, Inc. and subsidiaries and Constellation Investments, Inc.
(whose power projects are managed by Constellation Power) have $294.7 million
invested in 14 projects that sell electricity in California under power purchase
agreements called "Interim Standard Offer No. 4" agreements. Under these
agreements, the projects supply electricity to utility companies at:
o a fixed rate for capacity and energy for the first 10 years of the
agreements, and
o a fixed rate for capacity plus a variable rate for energy based on the
utilities' avoided cost for the remaining term of the agreements.
Generally, a "capacity rate" is paid to a power plant for its availability to
supply electricity, and an "energy rate" is paid for the electricity actually
generated. "Avoided cost" generally is the cost of a utility's cheapest
next-available source of generation to service the demands on its system.
We use the term "transitioned" to describe when the 10-year periods for fixed
energy rates have expired for these power generation projects and they began
supplying electricity at variable rates. The three remaining projects that have
not transitioned will do so by December 2000.
The projects that have already transitioned to variable rates have had lower
revenues under variable rates than they did under fixed rates. Once the
remaining projects have transitioned to variable rates, we expect the revenues
from those projects also to be lower than they are under fixed rates.
We discuss the earnings for these projects in the Nonregulated Businesses
section of Management's Discussion and Analysis on page 29.
Other Nonregulated Businesses
- -----------------------------
We discuss our other nonregulated businesses' activities further in the
Nonregulated Businesses section of Management's Discussion and Analysis on page
30.
16
Item 2. Management's Discussion
Management's Discussion and Analysis of Financial Condition and Results of
Operations
Introduction
- ------------
On April 30, 1999, Constellation Energy(R) Group, Inc. (Constellation Energy)
became the holding company for Baltimore Gas and Electric Company (BGE(R)) and
Constellation(R) Enterprises, Inc. Constellation Enterprises was previously
owned by BGE.
In response to the deregulation of electric generation, we realigned our
organization and combined our wholesale power marketing business with our
domestic plant development and operations to form a merchant energy business. In
2000, we revised our operating segments to reflect the realignments of our
organization, as presented in the Notes to Consolidated Financial Statements on
page 11.
Constellation Energy's subsidiaries primarily include BGE and a domestic
wholesale energy business focused mostly on power marketing and merchant
generation in North America.
BGE is a regulated electric and gas public utility company with a service
territory in the City of Baltimore and all or part of ten counties in Central
Maryland.
Our domestic wholesale energy segment includes the:
o wholesale power marketing of Constellation Power Source,(TM)Inc.,
o domestic power projects of Constellation Power, (TM)Inc., and subsidiaries
and Constellation Investments,(TM) Inc., and
o nuclear consulting services of Constellation Nuclear,(TM)LLC.
Through June 30, 2000, the financial results of the electric generation portion
of our business are included in BGE's regulated electric segment. After that
date, we will include the financial results of electric generation in the
domestic wholesale energy segment.
Our remaining nonregulated businesses include the:
o international power projects of Constellation Power, and subsidiaries,
o energy products and services of Constellation Energy Source,(TM)Inc.,
o home products, commercial building systems, and residential and commercial
gas retail marketing of BGE Home Products & Services,(TM) Inc. and
subsidiaries,
o general partnership, in which BGE is a partner, of District Chilled Water
General Partnership (ComfortLink(R)) that provides cooling services for
commercial customers in Baltimore,
o financial investments of Constellation Investments, and
o real estate and senior-living facilities of Constellation Real Estate
Group,(TM)Inc.
As a result of the deregulation of electric generation, we formed two
nonregulated subsidiaries that will be included in our domestic wholesale energy
segment -- Calvert Cliffs Nuclear Power Plant, Inc. and Constellation Power
Source Generation, Inc. Effective July 1, 2000, BGE transferred, at book value,
its generation assets and related liabilities to these entities.
Effective July 1, 2000, Calvert Cliffs Nuclear Power Plant, Inc. is a subsidiary
of Constellation Nuclear, LLC.
In addition, on July 1, 2000, we formed a nonregulated holding company,
Constellation Power Source Holdings, Inc., that includes:
o our wholesale power marketing of Constellation Power Source,
o our domestic power projects of Constellation Power and subsidiaries and
Constellation Investments, and
o the newly formed Constellation Power Source Generation subsidiary.
This Quarterly Report on Form 10-Q is a combined report of Constellation Energy
and BGE. The consolidated financial statements of Constellation Energy include
the accounts of Constellation Energy, BGE and its subsidiaries, Constellation
Enterprises, Inc. and its subsidiaries, and Constellation Nuclear, LLC and its
subsidiaries. The consolidated financial statements of BGE include the accounts
of BGE, ComfortLink, and BGE Capital Trust I. As Constellation Enterprises and
its subsidiaries were subsidiaries of BGE prior to April 30, 1999, they are
included in the consolidated financial statements of BGE through that date.
17
References in this report to "we" and "our" are to Constellation Energy and its
subsidiaries, collectively. Reference in this report to the "utility business"
is to BGE.
In this discussion and analysis, we explain the general financial condition and
the results of operations for Constellation Energy and BGE including:
o what factors affect our business,
o what our earnings and costs were in the periods presented,
o why earnings and costs changed between periods,
o where our earnings came from,
o how all of this affects our overall financial condition,
o what we expect our expenditures for capital projects to be in the future,
and
o where we expect to get cash for future capital expenditures.
As you read this discussion and analysis, refer to our Consolidated Statements
of Income on page 3, which present the results of our operations for the
quarters and six months ended June 30, 2000 and 1999. We analyze and explain the
differences between periods in the specific line items of the Consolidated
Statements of Income. Our analysis is important in making decisions about your
investments in Constellation Energy and/or BGE.
Also, this discussion and analysis is based on the operation of the electric
generation portion of our utility business under rate regulation. Our electric
business is currently changing as we have transferred our electric generation
assets and related liabilities to nonregulated subsidiaries of Constellation
Energy and we have entered into retail customer choice for electric generation
effective July 1, 2000. Accordingly, the results of operations and financial
condition described in this discussion and analysis are not necessarily
indicative of future performance.
Strategy
- --------
The change toward customer choice will significantly impact our business. In
response to this change, we regularly evaluate our strategies with two goals in
mind: to improve our competitive position, and to anticipate and adapt to
regulatory change. Currently, the majority of our earnings are from BGE. In the
future, we expect to derive almost two-thirds of our earnings from competitive
markets that are not limited by franchise boundaries.
While BGE will continue to be regulated and deliver electricity and natural gas
through its core distribution business, our growth strategies center on the
nonregulated domestic wholesale energy market with the objective of providing
new sources of earnings. As a result of our concentration on domestic merchant
energy, we decided to exit the international portion of our business in 1999. We
expect to complete our exit strategy by the end of 2000.
In addition, we might consider one or more of the following strategies:
o the complete or partial separation of our transmission and distribution
functions,
o the construction, purchase, or sale of generation assets,
o mergers or acquisitions of utility or non-utility businesses, and
o spin-off or sale of one or more businesses.
We cannot predict whether any of the strategies described above may actually
occur, or what their effect on our financial results or competitive position
might be. However, with the shift toward customer choice, competition, and the
growth of our nonregulated subsidiaries, various factors will affect our
financial results in the future. These factors include, but are not limited to,
operating our generation assets in a deregulated market without the benefit of a
fuel rate adjustment clause, the loss of revenues due to customers choosing
alternative suppliers, higher volatility of earnings and cash flows, and
increased financial requirements of our nonregulated subsidiaries. Please refer
to the Forward-Looking Statements section on page 37 for additional factors.
Also, these results will not be indicative of the future performance of BGE
since BGE transferred all of its generation assets and related liabilities to
nonregulated subsidiaries of Constellation Energy effective July 1, 2000. The
impact of such transfer on BGE's financial results will be material. The total
assets, liabilities, and common shareholders' equity of Constellation Energy
will not change as a result of the transfer.
18
Current Issues
- --------------
Competition - Electric
- ----------------------
Electric utilities are facing competition on various fronts, including:
o the construction of generating units to meet increased demand for
electricity,
o the sale of electricity in bulk power markets,
o competing with alternative energy suppliers, and
o electric sales to retail customers.
On April 8, 1999, Maryland enacted legislation authorizing customer choice and
competition among electric suppliers. In addition, on November 10, 1999, the
Maryland PSC issued a Restructuring Order that resolved the major issues
surrounding electric restructuring. Effective July 1, 2000, the state of
Maryland implemented customer choice for electric suppliers. These matters are
discussed further in this section and in Note 4 of our 1999 Annual Report on
Form 10-K.
As a result of the deregulation of BGE's electric generation and effective July
1, 2000, the following occurred:
o BGE transferred, at book value, its nuclear generating assets, its nuclear
decommissioning trust fund, and related liabilities to Calvert Cliffs
Nuclear Power Plant, Inc. In addition, BGE transferred, at book value, its
fossil generating assets and related liabilities and its partial ownership
interest in two coal plants and a hydroelectric plant located in
Pennsylvania to Constellation Power Source Generation, Inc. In total, these
generating assets represent about 6,240 megawatts of generation capacity
with a total net book value at June 30, 2000 of approximately $2.4 billion.
o BGE transferred approximately $47 million to Calvert Cliffs Nuclear Power
Plant, Inc. and $231 million to Constellation Power Source Generation, Inc.
of tax-exempt debt related to the transferred assets. Also, Constellation
Power Source Generation, Inc. issued approximately $366 million in
unsecured promissory notes to BGE. Repayments of the notes by Constellation
Power Source Generation, Inc. will be used exclusively to service the
current maturities of certain BGE long-term debt.
o BGE transferred equity associated with the generating assets to Calvert
Cliffs Nuclear Power Plant, Inc. and Constellation Power Source Generation,
Inc.
o The fossil fuel and nuclear fuel inventories, materials and supplies, and
certain purchased power contracts of BGE were also assumed by these
subsidiaries.
We present pro-forma financial statements for BGE as an exhibit to this
Quarterly Report on Form 10-Q (Exhibit 99). The information provided above and
in the pro-forma financial statements have been prepared using information
available at the date of this report.
Effective July 1, 2000, BGE will provide standard offer service to customers at
fixed rates over various time periods during the transition period for those
customers that do not choose an alternate supplier. In addition, the electric
fuel rate was discontinued effective July 1, 2000. Constellation Power Source
will provide BGE with the energy and capacity required to meet its standard
offer service obligations for the first three years of the transition period.
Thereafter, BGE will competitively bid the energy and capacity.
Constellation Power Source will obtain the energy and capacity to supply BGE's
standard offer service obligations from affiliates that own Calvert Cliffs
Nuclear Power Plant (Calvert Cliffs) and BGE's former fossil plants and from
purchased power contracts, supplemented with energy purchased from the wholesale
energy market as necessary. Our earnings will be exposed to the risks of the
competitive wholesale electricity market to the extent that Constellation Power
Source has to purchase energy and/or capacity to meet obligations to supply
power to BGE at market prices or costs, respectively, which may approach or
exceed BGE's standard offer service rates. If the price of obtaining energy in
the wholesale market exceeds the fixed standard offer service price, our
earnings would be adversely affected. We will also be affected by operational
risk, that is, the risk that a generating plant is not available to produce
energy when the energy is required. Imbalances in demand and supply can occur
not only because of plant outages, but also because of transmission constraints,
or extreme temperatures (hot or cold) causing demand to exceed available supply.
We cannot estimate the impact of the increased financial risks associated with
customer choice. However, these financial risks could have a material impact on
our, and BGE's, financial results.
19
Competition - Gas
- -----------------
Currently, no regulation exists for the wholesale price of natural gas as a
commodity, and the regulation of interstate transmission at the federal level
has been reduced. All BGE gas customers have the option to purchase gas from
other suppliers.
Early Retirement Program
- ------------------------
In recognition of the changing business environment, in 1999 our Board of
Directors approved a Targeted Voluntary Special Early Retirement Program
(TVSERP) to provide enhanced early retirement benefits to certain eligible
participants in targeted jobs that elected to retire on June 1, 2000. BGE
recorded approximately $10.0 million for employees that elected to participate
in the program. Of this amount, BGE recorded approximately $3.0 million on its
balance sheet as a regulatory asset of its gas business. We will amortize this
regulatory asset over a 5-year period as provided by the June 2000 Maryland PSC
gas base rate order. The remaining $7.0 million related to BGE's electric
business and was charged to expense. We discuss the gas base rate order further
in the Regulation by the Maryland PSC section on page 23. We discuss the impact
of the TVSERP on our financial results in the Results of Operations section on
page 26.
Calvert Cliffs License Extension
- --------------------------------
On March 23, 2000, the NRC approved a 20-year license extension for both units
of Calvert Cliffs, extending the license for Unit 1 to 2034 and for Unit 2 to
2036.
On April 11, 2000 the United States Court of Appeals for the District of
Columbia Circuit, in National Whistleblowers Center v. Nuclear Regulatory
Commission and Baltimore Gas and Electric Company, upheld the NRC's denial of
the Center's motion to intervene in BGE's license renewal proceeding. The NRC
had denied the Center's motion to intervene for failing to file timely
contentions.
Regional Transmission Organizations
- -----------------------------------
In December 1999, the FERC issued Order 2000, amending its regulations under the
Federal Power Act to advance the formation of Regional Transmission
Organizations (RTOs). The regulations require that each public utility that
owns, operates, or controls facilities for the transmission of electric energy
in interstate commerce make certain filings with respect to forming and
participating in a RTO. FERC also identified the minimum characteristics and
functions that a transmission entity must satisfy in order to be considered a
RTO.
According to the Order, a public utility that is a member of an existing
transmission entity that has been approved by FERC as in conformance with the
Independent System Operator (ISO) principles set forth in the FERC Order No.
888, such as BGE, through its membership in the PJM (Pennsylvania-New
Jersey-Maryland) Interconnection, must make a filing no later than January 15,
2001. That filing must explain the extent to which the transmission entity in
which it participates meets the minimum characteristics and functions of a RTO,
and either propose to modify the existing institution to the extent necessary to
become a RTO, or explain the efforts, obstacles, and plans with respect to
conforming to these characteristics and functions.
As a member of the PJM, an existing ISO, BGE does not expect to be materially
impacted by the Order. However, BGE, along with other members of the PJM, is
appealing certain aspects of the Order. We cannot determine the full impact of
the Order at this time.
20
Results of Operations for the Quarter and Six Months Ended June 30, 2000
Compared with the Same Periods of 1999
- --------------------------------------------------------------------------------
In this section, we discuss our earnings and the factors affecting them. We
begin with a general overview, then separately discuss earnings for our
operating segments.
Overview
- --------
Total Earnings Per Share of Common Stock
- ----------------------------------------
Quarter Ended Six Months Ended
June 30 June 30
--------------- ---------------
2000 1999 2000 1999
------- ------ ------ ------
Utility business...... $ .34 $ .37 $ .70 $ .82
Nonregulated businesses .03 .10 .18 .21
------- ------- ------ -----
Total earnings per
share before
nonrecurring
charges included
in operations ..... .37 .47 .88 1.03
Nonrecurring charges
included in
operations:
Deregulation
transition cost.. (.10) - (.10) -
TVSERP............. (.01) - (.03) -
Write-down of
financial
investment....... - (.02) - (.02)
------- ------- ------ ------
Total earnings per
share ............. $ .26 $ .45 $ .75 $1.01
======= ======= ====== ======
Quarter Ended June 30, 2000
- ---------------------------
Our total earnings for the quarter ended June 30, 2000 decreased $28.4 million,
or $.19 per share, compared to the same period of 1999. Our total earnings
decreased because we had lower earnings from our utility and nonregulated
businesses before nonrecurring charges. In addition, we recorded the following:
o a $24.0 million, or $15.0 million after-tax, deregulation transition cost to
a third party incurred by our power marketing business to provide BGE's
standard offer service requirements, and
o a $2.8 million, or $1.7 million after-tax, expense for BGE employees that
elected to participate in a Targeted Voluntary Special Early Retirement
Program (TVSERP) during the second quarter of 2000.
In the second quarter of 2000, utility earnings before nonrecurring charges
decreased compared to the same period of 1999 mostly due to the $37.5 million,
or $22.7 million after-tax, amortization of the regulatory asset recorded for
the reduction of BGE's generation plant as provided for under the Restructuring
Order. This was partially offset by higher electric and gas sales.
We discuss our utility earnings, the Restructuring Order, and the TVSERP in more
detail in the Utility Business section on page 22.
In the second quarter of 2000, nonregulated earnings before nonrecurring charges
decreased compared to the same period of 1999 mostly because of lower earnings
from our financial investments and international businesses. Earnings from our
domestic wholesale energy business were about the same compared to the same
period of 1999. We discuss our nonregulated earnings and the deregulation
transition cost in more detail in the Nonregulated Businesses section beginning
on page 28.
Six Months Ended June 30, 2000
- ------------------------------
Our total earnings for the six months ended June 30, 2000 decreased $39.1
million, or $.26 per share, compared to the same period of 1999. Our total
earnings decreased because we had lower earnings from our utility and
nonregulated businesses before nonrecurring charges. In addition, we recorded
the following:
o a $24.0 million, or $15.0 million after-tax, deregulation transition cost
to a third party incurred by our power marketing business to provide BGE's
standard offer service requirements, and
o a $7.0 million, or $4.2 million after-tax, expense for BGE employees that
elected to participate in the TVSERP.
In the six months ended June 30, 2000, utility earnings before nonrecurring
charges decreased compared to the same period of 1999 mostly due to the $75.0
million, or $45.4 million after-tax, amortization of the regulatory asset
recorded for the reduction of BGE's generation plant as provided for under the
Restructuring Order. This was partially offset by higher electric and gas sales.
In the six months ended June 30, 2000, nonregulated earnings before nonrecurring
charges decreased compared to the same period of 1999 mostly because of lower
earnings from our international business. This was partially offset by higher
earnings in our financial investments business and slightly higher earnings from
our domestic wholesale energy business.
21
Utility Business
- ----------------
Before we go into the details of our electric and gas operations, we believe it
is important to discuss factors that have a strong influence on our utility
business performance: electric restructuring, regulation by the Maryland PSC,
the weather, and other factors, including the condition of the economy in our
service territory.
Electric Restructuring
- ----------------------
On April 8, 1999, Maryland enacted the Electric Customer Choice and Competition
Act of 1999 (the "Act") and accompanying tax legislation that will significantly
restructure Maryland's electric utility industry and modify the industry's tax
structure.
In the Restructuring Order discussed below, the Maryland PSC addressed the major
provisions of the Act. The accompanying tax legislation is discussed in detail
in Note 4 of our 1999 Annual Report on Form 10-K.
On November 10, 1999, the Maryland PSC issued a Restructuring Order that
resolved the major issues surrounding electric restructuring, accelerated the
timetable for customer choice, and addressed the major provisions of the Act.
The Restructuring Order also resolved the electric restructuring proceeding
(transition costs, customer price protections, and unbundled rates for electric
services) and a petition filed in September 1998 by the Office of People's
Counsel (OPC) to lower our electric base rates. The major provisions of the
Restructuring Order are discussed below.
o All customers, except a few commercial and industrial companies that have
signed contracts with BGE, can choose their electric energy supplier
beginning July 1, 2000. BGE will provide a standard offer service for
customers that do not select an alternative supplier. In either case, BGE
will continue to deliver electricity to all customers in areas
traditionally served by BGE.
o BGE's electric base rates were frozen through June 30, 2000.
o BGE reduced 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 have up to four service options that
will fix electric energy rates and transition charges for a period that
generally ranges from four to six years.
o BGE's electric fuel rate clause was discontinued effective July 1, 2000.
o Electric delivery service rates are frozen for a four-year period for
commercial and industrial customers. The generation and transmission
components of rates are frozen for different time periods depending on the
service options selected by those customers.
o BGE will recover $528 million after-tax of its potentially stranded
investments and utility restructuring costs through a competitive
transition charge on customers' bills. Residential customers will pay this
charge for six years. Commercial and industrial customers will pay in a
lump sum or over the four to six-year period, depending on the service
option selected by each customer.
o Generation-related regulatory assets and nuclear decommissioning costs are
included in delivery service rates effective July 1, 2000 and will be
recovered on a basis approximating their amortization schedules prior to
July 1, 2000.
o Effective July 1, 2000, BGE unbundled rates to show separate components for
delivery service, transition charges, standard offer services (generation),
transmission, universal service, and taxes.
o Effective July 1, 2000, BGE transferred, 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 reduced its generation assets, as discussed in Note 4 of our 1999
Annual Report on Form 10-K, by $150 million pre-tax during the period July
1, 1999 - June 30, 2000 to mitigate a portion of BGE's potentially stranded
investments.
o Universal service will be provided for low-income customers without
increasing their bills. BGE will provide its share of a statewide fund
totaling $34 million annually.
We believe that the Restructuring Order provided sufficient details of the
transition plan to competition for BGE's electric generation business to require
BGE to discontinue the application of Statement of Financial Accounting
Standards (SFAS) No. 71, Accounting for the Effects of Certain Types of
Regulation for that portion of its business. Accordingly, in the fourth quarter
of 1999, we adopted the provisions of SFAS No. 101, Regulated Enterprises -
Accounting for the Discontinuation of FASB Statement No. 71 and Emerging Issues
Task Force
22
Consensus (EITF) No. 97-4, Deregulation of the Pricing of Electricity - Issues
Related to the Application of FASB Statements No. 71 and 101 for BGE's electric
generation business. BGE's transmission and distribution business continues to
meet the requirements of SFAS No. 71 as that business remains regulated. We
describe the effect of applying these accounting requirements in Note 4 of our
1999 Annual Report on Form 10-K.
Please refer to the Legal Proceedings section on page 35 for a discussion
regarding appeals of the Restructuring Order.
Regulation by the Maryland PSC
- ------------------------------
Under traditional rate regulation that continues after July 1, 2000 for BGE's
electric transmission and distribution, and gas businesses, the Maryland PSC
determines the rates we can charge our customers. Currently, our rates consist
of a "base rate," a "conservation surcharge," and a "fuel rate."
Base Rate
- ---------
The base rate is the rate the Maryland PSC allows us to charge our customers for
the cost of providing them service, plus a profit. We have both an electric base
rate and a gas base rate. Higher electric base rates apply during the summer
when the demand for electricity is higher. Gas base rates are not affected by
seasonal changes.
BGE may ask the Maryland PSC to increase base rates from time to time. The
Maryland PSC historically has allowed BGE to increase base rates to recover
increased utility plant asset costs, plus a profit, beginning at the time of
replacement. Generally, rate increases improve our utility earnings because they
allow us to collect more revenue. However, rate increases are normally granted
based on historical data and those increases may not always keep pace with
increasing costs. Other parties may petition the Maryland PSC to decrease base
rates.
On November 17, 1999, BGE filed an application with the Maryland PSC to increase
its gas base rates. On June 19, 2000, the Maryland PSC authorized a $6.4 million
annual increase in our gas base rates effective June 22, 2000.
As a result of the Restructuring Order, our residential electric base rates are
frozen until 2006.
Electric delivery service rates are frozen for a four-year period for commercial
and industrial customers. The generation and transmission components of rates
are frozen for different time periods depending on the service options selected
by those customers.
Conservation Surcharge
- ----------------------
The Maryland PSC allows us to include in electric and gas rates a component to
recover money spent on conservation programs. This component is called a
"conservation surcharge." However, under this surcharge the Maryland PSC limits
what our profit can be. If, at the end of the year we have exceeded our allowed
profit, we defer (include as a liability in our Consolidated Balance Sheets and
exclude from our Consolidated Statements of Income) the excess in that year and
we lower the amount of future surcharges to our customers to correct the amount
of overage, plus interest. As a result of the Restructuring Order, the electric
conservation surcharge was frozen and the associated profit limitation is no
longer applicable.
Fuel Rate
- ---------
Through June 30, 2000, we charged our electric customers separately for the fuel
we used to generate electricity (nuclear fuel, coal, gas, or oil) and for the
net cost of purchases and sales of electricity. We charged the actual cost of
these items to the customer with no profit to us. If these fuel costs went up,
the Maryland PSC permitted us to increase the fuel rate. If these costs went
down, our customers benefited from a reduction in the fuel rate. The fuel rate
was mostly impacted by the amount of electricity generated at Calvert Cliffs
because the cost of nuclear fuel is cheaper than coal, gas, or oil.
Under the Restructuring Order, BGE's electric fuel rate was frozen until July 1,
2000, at which time the fuel rate clause was discontinued. We deferred the
difference between our actual costs of fuel and energy and what we collected
from customers under the fuel rate through June 30, 2000. Currently, earnings
are affected by the changes in the cost of fuel and energy. We discuss our
exposure to market risk further in the Current Issues section on page 19. 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
through June 30, 2000 would be collected from our customers within a twelve
month period as determined by the Maryland PSC. At June 30, 2000, the
accumulated difference was $54.6 million.
We charge our gas customers separately for the natural gas they purchase from
us. The price we charge for the natural gas is based on a market based rates
incentive mechanism approved by the Maryland PSC. We discuss market based rates
in more detail in the Gas Cost Adjustments section on page 27 and in Note 1 of
our 1999 Annual Report on Form 10-K.
23
Weather
- -------
Weather affects the demand for electricity and gas. Very hot summers and very
cold winters increase demand. Mild weather reduces demand. Weather impacts
residential sales more than commercial and industrial sales, which are mostly
affected by business needs for electricity and gas.
We measure the weather's effect using "degree days." A degree day is the
difference between the average daily actual temperature and a baseline
temperature of 65 degrees. Cooling degree days result when the average daily
actual temperature exceeds the 65 degree baseline. Heating degree days result
when the average daily actual temperature is less than the baseline.
During the cooling season, hotter weather is measured by more cooling degree
days and results in greater demand for electricity to operate cooling systems.
During the heating season, colder weather is measured by more heating degree
days and results in greater demand for electricity and gas to operate heating
systems.
The Maryland PSC allows us to record a monthly adjustment to our gas business
revenues to eliminate the effect of abnormal weather patterns. We discuss this
further in the Weather Normalization section on page 27.
We show the number of heating degree days in the quarter and six months ended
June 30, 2000 and 1999, and the percentage change in the number of degree days
between these periods in the following table:
Quarter Ended Six Months Ended
June 30 June 30
----------------- -------------------
2000 1999 2000 1999
-------- ------ ------- --------
Heating degree days... 512 517 2,817 2,907
Percent change
from prior period (1.0)% (3.1)%
Cooling degree days... 263 203 268 204
Percent change
from prior period 29.6% 31.4%
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. Effective
July 1, 2000, BGE's electric customers can become delivery service customers
only and can purchase their electricity from other sources. The remaining
electric customers will receive standard offer service from BGE at the fixed
rates provided by the Restructuring Order. Usage per customer refers to all
other items impacting customer sales that cannot be measured separately. These
factors include the strength of the economy in our service territory. When the
economy is healthy and expanding, customers tend to consume more electricity and
gas. Conversely, during an economic downtrend, our customers tend to consume
less electricity and gas.
Utility Earnings Per Share of Common Stock
- ------------------------------------------
Quarter Ended Six Months Ended
June 30 June 30
--------------- ---------------
2000 1999 2000 1999
------- ------ ------ ------
Regulated electric
business .......... $ .32 $ .37 $ .55 $ .67
Regulated gas business .02 - .15 .15
----- ----- ------ ------
Total utility earnings
per share before
nonrecurring charge
included in
operations ........ .34 .37 .70 .82
Nonrecurring charge
included in operations:
TVSERP ............. (.01) - (.03) -
----- ----- ------ ------
Total utility earnings
per share ........ $ .33 $ .37 $ .67 $ .82
===== ===== ====== ======
Our utility earnings for the quarter ended June 30, 2000 decreased $6.0 million,
or $.04 per share compared to the same period of 1999. Our utility earnings for
the six months ended June 30, 2000, decreased $22.9 million, or $.15 per share
compared to the same six months of 1999. We discuss the factors affecting
utility earnings on page 25.
24
Regulated Electric Business
- ---------------------------
The discussion below reflects the operations of the electric generation portion
of our utility business under rate regulation by the Maryland PSC. As discussed
earlier in the Introduction and Current Issues sections, retail customer choice
for electric generation began effective July 1, 2000. Implementation of customer
choice will significantly impact our business.
Electric Revenues
- -----------------
The changes in electric revenues in 2000 compared to 1999 were caused by:
Quarter Ended Six Months Ended
June 30 June 30
2000 vs. 1999 2000 vs. 1999
--------------- ---------------
(In millions)
Electric system sales
volumes .............. $ 24.6 $ 33.0
Base rates ............. - -
Fuel rates ............. 9.4 12.6
------- ---------
Total change in electric
revenues from electric
system sales ...... 34.0 45.6
Interchange and
other sales ......... (4.1) (5.3)
Other .................. 2.4 3.4
------- ---------
Total change in
electric revenues ... $ 32.3 $ 43.7
======= =========
Electric System Sales Volumes
- -----------------------------
"Electric system sales volumes" are sales to customers in our service territory
at rates set by the Maryland PSC. These sales do not include interchange sales
and sales to others.
The percentage changes in our electric system sales volumes, by type of
customer, in 2000 compared to 1999 were:
Quarter Ended Six Months Ended
June 30 June 30
2000 vs. 1999 2000 vs. 1999
-------------- --------------
Residential....... 8.5% 5.4%
Commercial........ 8.5 6.0
Industrial........ 1.3 (0.3)
During the quarter ended June 30, 2000, we sold more electricity to residential
customers due to warmer spring and early summer weather. We sold more
electricity to commercial customers due to higher usage per customer, warmer
weather, and an increased number of customers. We sold more electricity to
industrial customers mostly because usage by Bethlehem Steel (our largest
customer) increased as a result of a 1999 shut down for a planned upgrade to
their facilities that temporarily reduced their electricity consumption in that
year.
During the six months ended June 30, 2000, we sold more electricity to
residential customers due to warmer spring and early summer weather and higher
usage per customer. We sold more electricity to commercial customers due to
higher usage per customer, warmer weather, and an increased number of customers.
We sold about the same amount of electricity to industrial customers. The
increase in usage by Bethlehem Steel was offset by lower usage by other
industrial customers.
Base Rates
- ----------
During the quarter and six months ended June 30, 2000, base rate revenues were
the same compared to the same periods of 1999.
Fuel Rates
- ----------
During the quarter and six months ended June 30, 2000, fuel rate revenues
increased compared to the same periods of 1999 mostly because we sold more
electricity.
Interchange and Other Sales
- ---------------------------
"Interchange and other sales" are sales in the PJM (Pennsylvania-New
Jersey-Maryland) Interconnection energy market and to others. The PJM is an ISO
that also operates a regional power pool with members that include many
wholesale market participants, as well as BGE, and other utility companies. We
sell energy to PJM members and to others after we have satisfied the demand for
electricity in our own system.
During the quarter and six months ended June 30, 2000, we had lower interchange
and other sales compared to the same periods of 1999 mostly because the
increased demand for system sales reduced the amount of energy we had available
for off-system sales.
Electric Fuel and Purchased Energy Expenses
- -------------------------------------------
Quarter Ended Six Months Ended
June 30 June 30
------------------- ----------------
2000 1999 2000 1999
-------- ------- ------ -------
(In millions)
Actual costs.......... $ 126.0 $ 130.6 $ 247.8 $ 257.9
Net deferral of cost
under electric fuel
rate clause ........ (6.5) (10.6) (9.7) (16.7)
------- -------- ------- --------
Total electric fuel
and purchased energy
expenses........... $ 119.5 $ 120.0 $ 238.1 $ 241.2
======== ======== ======= ========
Actual Costs
- ------------
During the quarter and six months ended June 30, 2000, our actual costs of fuel
to generate electricity (nuclear fuel, coal, gas, or oil) and electricity we
bought from others were lower compared to the same periods of 1999 mostly
because of lower purchased energy costs.
25
Electric Fuel Rate Clause
- -------------------------
Under the electric fuel rate clause, we deferred (included as an asset or
liability on the Consolidated Balance Sheets and excluded from the Consolidated
Statements of Income) the difference between our actual costs of fuel and energy
and what we collected from customers under the fuel rate in a given period.
Effective July 1, 2000, the electric fuel rate clause was discontinued. We
discuss the accumulated difference between our actual costs and what we
collected through June 30, 2000 in the Fuel Rate section on page 23.
During the quarter and six months ended June 30, 2000, our actual costs of fuel
and energy were higher than the fuel rate revenues we collected from our
customers.
Electric Operations and Maintenance Expenses
- ----------------------------------------------
During the quarter ended June 30, 2000, electric operations and maintenance
expenses increased $4.9 million compared to 1999 mostly because we recorded $2.8
million of expense for electric business employees that elected to participate
in the TVSERP during the period.
During the six months ended June 30, 2000, electric operations and maintenance
expenses were about the same compared to the same period of 1999. During 2000,
we recorded $7.0 million of expense for electric business employees that elected
to participate in the TVSERP. This was offset by higher expenses in 1999 for
employee benefit costs and costs related to a major winter ice storm that
increased expenses in that year.
Electric Depreciation and Amortization Expense
- ----------------------------------------------
During the quarter ended June 30, 2000, electric depreciation and amortization
expense increased $36.4 million compared to 1999 mostly because of the $37.5
million amortization of the regulatory asset for the reduction in generation
plant provided for in the Restructuring Order.
During the six months ended June 30, 2000, electric depreciation and
amortization expense increased $76.0 million compared to 1999 mostly because of
the $75.0 million amortization of the regulatory asset for the reduction in
generation plant provided for in the Restructuring Order.
Regulated Gas Business
- ----------------------
All BGE customers have the option to purchase gas from other suppliers. To date,
customer choice has not had a material effect on our, and BGE's, financial
results.
Gas Revenues
- ------------
The changes in gas revenues in 2000 compared to 1999 were caused by:
Quarter Ended Six Months Ended
June 30 June 30
2000 vs. 1999 2000 vs. 1999
-------------- ----------------
(In millions)
Gas system
sales volumes .......... $ 3.3 $ 7.3
Base rates ................ - (0.5)
Weather normalization ..... (0.6) (3.4)
Gas cost adjustments ...... 0.2 (13.2)
----------- -----------
Total change in gas
revenues from gas
system sales............. 2.9 (9.8)
Off-system sales........... 8.8 22.9
Other ..................... - 0.3
----------- -----------
Total change in
gas revenues ........... $ 11.7 $ 13.4
=========== ===========
Gas System Sales Volumes
- ------------------------
The percentage changes in our gas system sales volumes, by type of customer, in
2000 compared to 1999 were:
Quarter Ended Six Months Ended
June 30 June 30
2000 vs. 1999 2000 vs. 1999
-------------- ----------------
Residential............... 2.7% 1.3%
Commercial................ 7.5 5.2
Industrial................ 13.2 4.5
During the quarter ended June 30, 2000, we sold more gas to residential
customers compared to the same period of 1999 due to an increased number of
customers. We sold more gas to commercial customers mostly because of higher
usage per customer. We sold more gas to industrial customers mostly because
usage by Bethlehem Steel (our largest customer) and other industrial customers
increased. Usage by Bethlehem Steel increased as a result of a 1999 shut down
for a planned upgrade to their facilities that temporarily reduced their gas
consumption in that year. This was partially offset by a decrease in the number
of customers.
During the six months ended June 30, 2000, we sold more gas to residential and
commercial customers compared to the same period of 1999 due to higher usage per
customer and an increased number of customers. This was partially offset by
milder winter weather. We sold more gas to industrial customers mostly because
usage by Bethlehem Steel and other industrial customers increased. This was
partially offset by a decrease in the number of customers.
26
Base Rates
- ----------
During the quarter and six months ended June 30, 2000, base rate revenues were
about the same compared to the same periods of 1999.
On June 19, 2000, the Maryland PSC authorized a $6.4 million annual increase in
our base rates effective June 22, 2000.
Weather Normalization
- ---------------------
The Maryland PSC allows us to record a monthly adjustment to our gas revenues to
eliminate the effect of abnormal weather patterns on our gas system sales
volumes. This means our monthly gas revenues are based on weather that is
considered "normal" for the month and, therefore, are not affected by actual
weather conditions.
Gas Cost Adjustments
- --------------------
We charge our gas customers for the natural gas they purchase from us using gas
cost adjustment clauses set by the Maryland PSC. These clauses operate similarly
to the electric fuel rate clause described in the Electric Fuel Rate Clause
section on page 26. 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 June 30, 2000, gas cost adjustment revenues were about
the same compared to the same period of 1999.
During the six months ended June 30, 2000, gas cost adjustment revenues
decreased compared to the same period of 1999 mostly because we sold less gas to
non-delivery service customers. This was partially offset by a higher price of
gas sold.
Off-System Sales
- ----------------
Off-system gas sales are low-margin direct sales of gas to wholesale suppliers
of natural gas outside our service territory. Off-system gas sales, which occur
after we have satisfied our customers' demand, are not subject to gas cost
adjustments. The Maryland PSC approved an arrangement for part of the margin
from off-system sales to benefit customers (through reduced costs) and the
remainder to be retained by BGE (which benefits shareholders). Changes in
off-system sales do not significantly impact earnings.
During the quarter and six months ended June 30, 2000, revenues from off-system
gas sales increased compared to the same periods of 1999 mostly because we sold
more gas off-system at a higher price.
Gas Purchased For Resale Expenses
- ---------------------------------
Quarter Ended Six Months Ended
June 30 June 30
------------------- ------------------
2000 1999 2000 1999
-------- ------- -------- --------
(In millions)
Actual costs............ $ 43.4 $ 29.8 $ 149.5 $ 123.0
Net (deferral) recovery
of costs under gas
adjustment clause..... (2.6) 3.2 (5.8) 12.1
-------- -------- ------- --------
Total gas purchased
for resale $ 40.8 $ 33.0 $ 143.7 $ 135.1
expenses............... ======== ======== ======= =======
Actual Costs
- ------------
Actual costs include the cost of gas purchased for resale to our customers and
for off-system sales. Actual costs do not include the cost of gas purchased by
delivery service customers.
During the quarter and six months ended June 30, 2000, actual gas costs
increased compared to the same periods of 1999 mostly because we bought more gas
for off-system sales and all of the gas purchased was at a higher price.
Gas Adjustment Clauses
- ----------------------
We charge customers for the cost of gas sold through gas adjustment clauses
(determined by the Maryland PSC), as discussed under Gas Cost Adjustments
earlier in this section.
During the quarter and six months ended June 30, 2000, our actual gas costs were
higher than the fuel rate revenues we collected from our customers.
Gas Operations and Maintenance Expenses
- ---------------------------------------
During the quarter and six months ended June 30, 2000, gas operations and
maintenance expenses decreased slightly compared to the same periods of 1999.
Gas Depreciation and Amortization Expense
- -----------------------------------------
During the quarter and six months ended June 30, 2000, gas depreciation and
amortization expense was about the same compared to the same periods of 1999.
27
Nonregulated Businesses
- -----------------------
Our nonregulated businesses engage primarily in domestic wholesale energy
services as discussed in the Introduction section on page 17. We describe our
nonregulated businesses in more detail in our 1999 Annual Report on Form 10-K in
Item 1. Business -- Diversified Businesses.
Nonregulated Earnings Per Share of Common Stock
- -----------------------------------------------
Quarter Ended Six Months Ended
June 30 June 30
-------------- ---------------
2000 1999 2000 1999
------- ------ ------ --------
Domestic wholesale energy
Power marketing........... $ .05 $ .08 $ .14 $ .13
Domestic power projects... .05 .03 .09 .08
------- ------- ------- -------
Total domestic wholesale
energy earnings
per share before
nonrecurring charges
included in operations.... .10 .11 .23 .21
Other nonregulated
businesses earnings (loss)
per share before
nonrecurring charges
included in operations.... (.07) (.01) (.05) -
------- ------- ------- -------
Total nonregulated earnings
per share before
nonrecurring charges
included in operations.... .03 .10 .18 .21
Nonrecurring charges
included in operations:
Deregulation transition
cost.................... (.10) - (.10) -
Write-down of financial
investment.............. - (.02) - (.02)
------- ------- ------- -------
Total nonregulated earnings
(loss) per share.......... $ (.07) $ .08 $ .08 $ .19
======= ======= ======= =======
Our total nonregulated earnings for the quarter ended June 30, 2000 decreased
$22.4 million, or $.15 per share, compared to the same period of 1999. Our total
nonregulated earnings for the six months ended June 30, 2000 decreased $16.2
million, or $.11 per share, compared to the same period of 1999.
We discuss the factors affecting the earnings of our nonregulated businesses
below.
Domestic Wholesale Energy
- -------------------------
Power Marketing
- ---------------
During the quarter ended June 30, 2000, earnings from our power marketing
business before nonrecurring charges decreased compared to the same period of
1999 mostly because of lower margins, and increased operating expenses
associated with the growth of the business.
During the six months ended June 30, 2000, earnings from our power marketing
business before nonrecurring charges increased slightly compared to the same
period of 1999 mostly because of increased transaction volumes, partially offset
by lower margins, and increased operating expenses associated with the growth of
the business.
As discussed in the Current Issues section on page 19, Constellation Power
Source provides BGE with the energy and capacity required to meet its standard
offer service obligations for the first three years of the transition period
effective July 1, 2000.
Constellation Power Source will obtain the energy and capacity to supply BGE's
standard offer service obligations from affiliates that own Calvert Cliffs and
BGE's former fossil plants and from purchased power contracts, supplemented with
energy purchased from the wholesale energy market as necessary and will also
manage our wholesale market price risk.
In June 2000, Constellation Power Source recognized a $15.0 million after-tax,
or $.10 per share, deregulation transition cost to a third party related to
BGE's standard offer service requirements.
Constellation Power Source uses the mark-to-market method of accounting. We
discuss the mark-to-market method of accounting and Constellation Power Source's
activities in more detail in Note 1 of our 1999 Annual Report on Form 10-K.
As a result of the nature of its business activities, Constellation Power
Source's revenue and earnings will fluctuate. We cannot predict these
fluctuations, but the effect on our revenues and earnings could be material. The
primary factors that cause these fluctuations are:
o the number and size of new transactions,
o the magnitude and volatility of changes in commodity prices and interest
rates, and
o the number and size of open commodity and derivative positions
Constellation Power Source holds or sells.
28
Constellation Power Source's management uses its best estimates to determine the
fair value of commodity and derivative positions it holds and sells. These
estimates consider various factors including closing exchange and
over-the-counter price quotations, time value, volatility factors, and credit
exposure. However, it is possible that future market prices could vary from
those used in recording assets and liabilities from power marketing and trading
activities, and such variations could be material. Assets and liabilities from
energy trading activities (as shown in our Consolidated Balance Sheets beginning
on page 4) increased at June 30, 2000 compared to December 31, 1999 because of
business growth during the period.
Domestic Power Projects
- -----------------------
During the quarter and six months ended June 30, 2000, earnings from our
domestic power projects business increased compared to the same periods of 1999
mostly because our domestic power projects business recognized an $8.2 million
after-tax, or $.05 per share, gain on the termination of an operating
arrangement and the sale of certain subsidiaries. This increase was partially
offset by lower earnings from our California power purchase agreements. These
are discussed in further detail below.
In April 2000, Constellation Operating Services, Inc. (COSI), a subsidiary of
Constellation Power, Inc., ended its exclusive arrangement with Orion Power
Holdings, Inc. to operate Orion's facilities. Orion purchased from COSI the four
subsidiary companies formed to operate power plants owned by Orion. As a result,
COSI recognized an $8.2 million after-tax gain during the second quarter of
2000.
California Power Purchase Agreements
- ------------------------------------
Constellation Power and subsidiaries and Constellation Investments have $294.7
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 $1.9 million, or $.01 per share, for the quarter ended
June 30, 2000 compared to $5.9 million, or $.04 per share for the same period of
1999. Earnings from these projects were $8.8 million, or $.06 per share, for the
six months ended June 30, 2000 compared to $13.9 million, or $.09 per share for
the same period of 1999.
Under these agreements, the electricity rates change from fixed rates to
variable rates beginning in 1996 and continuing through 2000. The projects which
already have had rate changes have lower revenues under variable rates than they
did under fixed rates. When the remaining projects transition to variable rates,
we expect their revenues also to be lower than they are under fixed rates.
At the date of this report, 11 projects had already transitioned to variable
rates. The remaining three projects will transition in November and December
2000. Those projects changing over later in 2000 contributed $3.6 million, or
$.02 per share to the quarter ended June 30, 2000 earnings and $8.7 million, or
$.06 per share to the six months ended June 30, 2000 earnings.
Our power projects business continues to pursue alternatives for some of these
projects including:
o repowering the projects to reduce operating costs,
o changing fuels to reduce operating costs,
o renegotiating the power purchase agreements to improve the terms,
o restructuring financing to improve existing terms, and
o selling its ownership interests in the projects.
We evaluate the carrying amount of our investment in these projects for
impairment using the methodology discussed in Note 1 of our 1999 Annual Report
of Form 10-K. Constellation Power's management uses its best estimates to
determine if there has been an impairment of these investments and considers
various factors including forward price curves for energy, fuel costs, and
operating costs. However, it is possible that future estimates of market prices
and project costs could vary from those used in evaluating these assets, and the
impact of such variations could be material.
We also describe these projects and the transition process in the Notes to
Consolidated Financial Statements on page 16.
29
Other Nonregulated Businesses
- -----------------------------
During the quarter ended June 30, 2000, earnings from our other nonregulated
businesses before nonrecurring charges decreased compared to the same period of
1999 mostly because of lower earnings from our financial investments and
international businesses. Our financial investments business had lower earnings
due to a decline in its market performance, and our international business had
lower earnings primarily due to increased operating expenses in Guatemala.
During the six months ended June 30, 2000, earnings from our other nonregulated
businesses before nonrecurring charges decreased compared to the same period of
1999 mostly because of lower earnings from our international business. This was
partially offset by higher earnings from our financial investments business due
to better market performance of its investments.
In December 1999, we decided to exit the international portion of our power
projects business as part of our strategy to improve our competitive position.
We expect to complete our exit strategy by the end of 2000. We discuss our
strategy further in the Strategy section on page 18.
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 for the exchange of its shares of common stock in Capital
Re for common stock of ACE Limited. This exchange is discussed further in our
1999 Annual Report on Form 10-K.
Most of Constellation Real Estate Group's real estate and senior-living projects
are in the Baltimore-Washington corridor. The area has had a surplus of
available land in recent years and as a result these projects have been
economically hurt.
Constellation Real Estate's projects have continued to incur carrying costs and
depreciation over the years. Additionally, this business has been charging
interest payments to expense rather than capitalizing them for some undeveloped
land where development activities have stopped. These carrying costs,
depreciation, and interest expenses have decreased earnings and are expected to
continue to do so.
Cash flow from real estate and senior-living operations has not been enough to
make the monthly loan payments on some of these projects. Cash shortfalls have
been covered by cash obtained from the cash flows of, or additional borrowings
by, other nonregulated subsidiaries.
We consider market demand, interest rates, the availability of financing, and
the strength of the economy in general when making decisions about our real
estate and senior-living projects. If we were to decide to sell our projects, we
could have write-downs. In addition, if we were to sell our projects in the
current market, we would have losses which could be material, although the
amount of the losses is hard to predict. Depending on market conditions, we
could also have material losses on any future sales.
Our current real estate and senior-living strategy is to hold each project until
we can realize a reasonable value for it. Under accounting rules, we are
required to write down the value of a project to market value in either of two
cases. The first is if we change our intent about a project from an intent to
hold to an intent to sell and the market value of that project is below book
value. The second is if the expected cash flow from the project is less than the
investment in the project.
Consolidated Nonoperating Income and Expenses
- ---------------------------------------------
Fixed Charges
- -------------
During the quarter and six months ended June 30, 2000, fixed charges increased
compared to the same periods of 1999 mostly because we had more debt
outstanding.
Income Taxes
- ------------
During the quarter ended June 30, 2000, our total income taxes decreased
compared to the same period of 1999 mostly because we had lower taxable income
partially offset by a $7.0 million increase at BGE as a result of comprehensive
changes to the state and local tax laws. We discuss the comprehensive tax law
changes in Note 4 of our 1999 Annual Report on Form 10-K.
During the six months ended June 30, 2000, our total income taxes decreased
compared to the same period of 1999 mostly because we had lower taxable income
partially offset by a $17.3 million increase at BGE as a result of comprehensive
changes to the state and local tax laws.
30
Financial Condition
- -------------------
Cash Flows
- ----------
Six Months Ended
June 30
--------------------
2000 1999
---------- ---------
(In millions)
Cash provided by (used in):
Operating Activities $342.3 $370.2
Investing Activities (458.1) (195.5)
Financing Activities 169.5 (245.0)
During the six months ended June 30, 2000, we generated less cash from
operations compared to the same period in 1999 mostly because of changes in
working capital requirements.
During the six months ended June 30, 2000, we used more cash for investing
activities compared to the same period in 1999 mostly due to an increase in
investments in our domestic power projects business and Orion and an increase in
utility construction expenditures. In addition, our real estate and
senior-living facilities business received less cash compared to the same period
of 1999, due to the sale of a project in 1999. We did not have a similar sale in
2000.
During the six months ended June 30, 2000, we had more cash from financing
activities compared to the same period of 1999 mostly because we issued more
long-term debt. This was partially offset by repayment of our short-term
borrowings that matured.
Security Ratings
- ----------------
Independent credit-rating agencies rate Constellation Energy and BGE's
fixed-income securities. The ratings indicate the agencies' assessment of each
company's ability to pay interest, distributions, dividends, and principal on
these securities. These ratings affect how much it will cost each company to
sell these securities. The better the rating, the lower the cost of the
securities to each company when they sell them. Constellation Energy and BGE's
securities ratings at the date of this report are:
Standard Moody's Duff & Phelps'
& Poors Investors Credit
Rating Group Service Rating Co.
------------ ----------- -------------
Constellation Energy
- --------------------
Unsecured Debt A- A3 A
BGE
- ---
Mortgage Bonds AA- A1 AA-
Unsecured Debt A A2 A+
Trust Originated
Preferred Securities
and Preference Stock A- "a2" A
Capital Resources
- -----------------
Our business requires a great deal of capital. Our estimated annual amounts for
the years 2000 through 2002, are shown in the table on page 32. For the twelve
months ended June 30, 2000, the ratio of earnings to fixed charges for
Constellation Energy was 2.61. The ratio of earnings to fixed charges for BGE
was 3.40 and the ratio of earnings to combined fixed charges and preferred and
preference dividend requirements for BGE was 3.06.
We will continue to have cash requirements for:
o working capital needs including the payments of interest, distributions,
and dividends,
o capital expenditures, and
o the retirement of debt and redemption of preference stock.
Capital requirements for 2000 through 2002 include estimates of funding for
existing and anticipated projects. We continuously review and modify those
estimates. Actual requirements may vary from the estimates included in the table
on page 32 because of a number of factors including:
o regulation, legislation, and competition,
o BGE load requirements,
o environmental protection standards,
o the type and number of projects selected for development,
o the effect of market conditions on those projects,
o the cost and availability of capital, and
o the availability of cash from operations.
Our estimates are also subject to additional factors. Please see the
Forward-Looking Statements section on page 37.
Effective July 1, 2000, all of BGE's generation assets were transferred to
nonregulated subsidiaries of Constellation Energy. The discussion and table for
capital requirements on page 32 include these generation assets as part of the
utility's regulated electric business through June 30, 2000. After that date,
the capital requirements are included in the domestic wholesale energy business.
31
Calendar Year Estimates
2000 2001 2002
-------------- ------------- ------------
(In millions)
Utility Capital Requirements:
- -----------------------------
Construction expenditures (excluding AFC):
Regulated Electric:
Generation (including nuclear fuel) $ 94 $ - $ -
Transmission and distribution 177 167 167
--------- -------- --------
Total regulated electric 271 167 167
Regulated Gas 56 54 54
Common 22 18 18
--------- -------- --------
Total construction expenditures 349 239 239
Retirement of long-term debt and redemption of
preference stock 122 194 148
--------- -------- --------
Total utility capital requirements 471 433 387
--------- -------- --------
Nonregulated Capital Requirements:
- ----------------------------------
Investment requirements:
Domestic Wholesale Energy 697* 1,241 1,078
Other 47 54 42
--------- -------- --------
Total investment requirements 744 1,295 1,120
Retirement of long-term debt 583 439 7
--------- -------- --------
Total nonregulated capital requirements 1,327 1,734 1,127
--------- -------- --------
Total capital requirements $1,798 $2,167 $1,514
========= ======== ========
* Effective July 1, 2000, includes approximately $110 million for electric
generation and nuclear fuel formerly part of BGE's regulated electric business.
Capital Requirements
- --------------------
Electric Generation
- -------------------
Electric construction expenditures for our regulated electric segment include
improvements to generating plants and costs for replacing the steam generators
at Calvert Cliffs through June 30, 2000. Thereafter, these expenditures are
reflected in our domestic wholesale energy segment.
In March 2000, we received the license extension from the NRC that extends our
operating licenses to 2034 for Unit 1 and 2036 for Unit 2 as discussed in the
Current Issues section on page 20. If we do not replace the steam generators, we
will not be able to operate these units through our operating licenses period.
We expect the steam generator replacement to occur during the 2002 refueling
outage for Unit 1 and during the 2003 refueling outage for Unit 2. We estimate
these Calvert Cliffs' costs to be:
o $ 40 million in 2000,
o $ 64 million in 2001,
o $ 88 million in 2002, and
o $ 60 million in 2003.
Additionally, our estimates of future electric generation construction
expenditures include the costs of complying with Environmental Protection Agency
(EPA) and State of Maryland nitrogen oxides emissions (NOx) reduction
regulations as follows:
o $ 63 million in 2000,
o $ 52 million in 2001, and
o $ 4 million in 2002.
We discuss the NOx regulations and timing of expenditures in the Environmental
Matters section of the Notes to Consolidated Financial Statements on page 14.
Electric Transmission and Distribution, and Gas
- -----------------------------------------------
Regulated electric transmission and distribution, and gas construction
expenditures primarily include new business construction needs and improvements
to existing facilities.
32
Domestic Wholesale Energy Business
- ----------------------------------
Our domestic wholesale energy business will require additional funding for
growing its power marketing business and developing and acquiring power
projects.
Our domestic wholesale energy business investment requirements include the
planned construction of 1,100 megawatts of peaking capacity in the
Mid-Atlantic/Mid-West region by the summer of 2001 and an additional 4,300
megawatts of peaking and combined cycle production facilities scheduled for
completion in 2002 and beyond in the Mid-West and South regions.
Our investment requirements also include our domestic wholesale energy business
commitment to contribute up to an additional $19.5 million in equity to Orion.
To date, our domestic wholesale energy business has funded $205.5 million in
equity to Orion.
Funding for Capital Requirements
- --------------------------------
BGE
- ---
Our utility business has met its capital requirements in the past primarily
through internally generated funds. When BGE could not meet utility capital
requirements internally, BGE sold debt and preference stock.
BGE also sells securities when market conditions permit it to refinance existing
debt or preference stock at a lower cost. The amount of cash BGE needs and
market conditions determine when and how much BGE sells.
Future funding for capital expenditures is expected from internally generated
funds, commercial paper issuances, available capacity under credit facilities,
the issuance of long-term debt, trust securities, or preference stock, and/or
from time to time equity contributions from Constellation Energy.
At June 30, 2000, FERC authorized BGE to issue up to $700 million of short-term
borrowings, including commercial paper. In addition, BGE maintains $183 million
in annual committed bank lines of credit and has $60 million in bank revolving
credit agreements to support the commercial paper program. In addition, BGE has
access to interim lines of credit as required from time to time to support its
outstanding commercial paper.
Domestic Wholesale Energy Business
- ----------------------------------
Our domestic wholesale energy business has met its capital requirements in the
past through borrowing, cash from its operations, and from time to time equity
contributions from BGE or Constellation Energy.
Future funding for the expansion of our domestic wholesale energy business is
expected from internally generated funds, commercial paper issuances and
long-term debt financing by Constellation Energy, and from time to time equity
contributions from Constellation Energy.
At June 30, 2000, Constellation Energy has a commercial paper program where it
can issue up to $500 million in short-term notes to fund its nonregulated
businesses. To support its commercial paper program, Constellation Energy
maintains two revolving credit agreements totaling $565 million, of which one
facility can also issue letters of credit. In addition, Constellation Energy has
access to interim lines of credit as required from time to time to support its
outstanding commercial paper.
Other Nonregulated Businesses
- -----------------------------
BGE Home Products & Services may meet capital requirements through sales of
receivables. ComfortLink has a revolving credit agreement totaling $50 million
to provide liquidity for short-term financial needs.
If we can get a reasonable value for our real estate projects, senior-living
facilities, and other investments, additional cash may be obtained by selling
them. Our ability to sell or liquidate assets will depend on market conditions,
and we cannot give assurances that these sales or liquidations could be made. We
discuss the real estate and senior-living facilities business and market
conditions in the Other Nonregulated Businesses section on page 30.
33
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 14
and in our 1999 Annual Report on Form 10-K in Item 1. Business - Environmental
Matters. These details include financial information. Some of the information is
about costs that may be material.
Accounting Standards Issued
- ---------------------------
In June 2000, the FASB issued Statement of Financial Accounting Standards (SFAS)
No. 138, Accounting for Certain Derivative Instruments and Certain Hedging
Activities, that amends certain provisions of SFAS No. 133, Accounting for
Derivative Instruments and Hedging Activities and addresses a limited number of
implementation issues related to SFAS No. 133.
In July 1999, the FASB issued SFAS No. 137 that delays the effective date for
SFAS No. 133 by one year. Therefore, we must adopt the provisions of SFAS No.
133 in our financial statements for the quarter ended March 31, 2001.
We are evaluating the implications of SFAS Nos. 133 and 138, but have not
determined the effects on our financial results. However, SFAS Nos. 133 and 138
will not significantly impact our power marketing business as this business uses
mark-to-market accounting.
Item 3. Quantitative and Qualitative Disclosures About Market Risk
We discuss the following information related to our market risk:
o risk associated with the purchase and sale of energy in a deregulated
environment as discussed in the Current Issues section of Management's
Discussion and Analysis on page 19,
o financing activities in the Notes to Consolidated Financial Statements on
page 13, and
o activities of our power marketing business in the Power Marketing section
of Management's Discussion and Analysis on page 28.
34
PART II. OTHER INFORMATION
Item 1. Legal Proceedings
- --------------------------
Asbestos
- --------
Since 1993, we have been involved in several actions concerning asbestos. The
actions are based upon the theory of "premises liability," alleging that we knew
of and exposed individuals to an asbestos hazard. The actions relate to two
types of claims.
The first type is direct claims by individuals exposed to asbestos. We described
these claims in BGE's Report on Form 8-K filed August 20, 1993. We are involved
in these claims with approximately 70 other defendants. Approximately 530
individuals that were never employees of BGE each claim $6 million in damages
($2 million compensatory and $4 million punitive). These claims were filed in
the Circuit Court for Baltimore City, Maryland in the summer of 1993. We do not
know the specific facts necessary to estimate our potential liability for these
claims. The specific facts we do not know include:
o the identity of our facilities at which the plaintiffs allegedly worked as
contractors,
o the names of the plaintiff's employers, and
o the date on which the exposure allegedly occurred.
To date, 25 of these cases were settled for amounts that were not significant.
The second type is claims by one manufacturer -- Pittsburgh Corning Corp. --
against us and approximately eight others, as third-party defendants. These
claims relate to approximately 1,500 individual plaintiffs and were filed in the
Circuit Court for Baltimore City, Maryland in the fall of 1993. To date, about
260 cases have been resolved, all without any payments by BGE. We do not know
the specific facts necessary to estimate our potential liability for these
claims. The specific facts we do not know include:
o the identity of our facilities containing asbestos manufactured by the
manufacturer,
o the relationship (if any) of each of the individual plaintiffs to us,
o the settlement amounts for any individual plaintiffs who are shown to have
had a relationship to us, and
o the dates on which/places at which the exposure allegedly occurred.
Until the relevant facts for both types of claims are determined, we are unable
to estimate what our liability, if any, might be. Although insurance and hold
harmless agreements from contractors who employed the plaintiffs may cover a
portion of any awards in the actions, our potential liability could be material.
Restructuring Order
- -------------------
In early December 1999, the Mid-Atlantic Power Supply Association (MAPSA),
Trigen-Baltimore Energy Corporation and Sweetheart Cup Company, Inc. filed
appeals of the Restructuring Order, which were consolidated in the Baltimore
City Circuit Court. MAPSA also filed a motion to delay implementation of the
Restructuring Order, pending a decision on the merits of the appeals by the
court.
On April 21, 2000, the Circuit Court dismissed MAPSA's appeal based on a lack of
standing (the right of a party to bring a lawsuit to court) and denied its
motion for a delay of the Restructuring Order. However, MAPSA filed an appeal of
this decision. On May 24, 2000, the Circuit Court dismissed both the Trigen and
Sweetheart Cup appeals.
On June 30, 2000, the Maryland Court of Appeals granted MAPSA's petition to
review whether MAPSA had standing to challenge the merits of the Restructuring
Order and ordered a delay of the implementation of the Restructuring Order.
On July 20, 2000, the Court of Appeals rescinded its delay of implementation of
the Restructuring Order, but found that MAPSA had standing, sending the case
back to the Circuit Court.
On July 21, 2000, the Circuit Court re-imposed the delay of implementation of
the Restructuring Order to review the filings in the case. The Circuit Court
rescinded its delay on August 4, 2000; however, a hearing on the merits of the
Restructuring Order is scheduled for August 23, 2000.
The effect of the appeals of the Restructuring Order was to delay the
implementation of customer choice in BGE's service territory. However, once the
delay was rescinded on August 4, 2000, BGE agreed to retroactively adjust its
rates as if customer choice had been implemented July 1, 2000. While we believe
that MAPSA's case is without merit, no assurance can be given as to its timing
or outcome, which could have a material adverse effect on our, and BGE's,
financial results.
Asset Transfer Order
- --------------------
On July 6, 2000, MAPSA and Shell Energy LLC filed, in the Circuit Court for
Baltimore City, a petition for review and a delay of the Maryland PSC's order
approving the transfer of BGE's generation assets issued on June 19, 2000. The
Court denied the delay on August 4, 2000. A hearing on the petition is scheduled
for August 23, 2000. We also believe that this petition is without merit.
However, we cannot predict the timing, or outcome, of this case, which could
have a material adverse effect on our, and BGE's, financial results.
35
Item 4. Submission of Matters to a Vote of Security Holders
On April 28, 2000, Constellation Energy Group held its annual meeting of
shareholders. At that meeting, the following matters were voted upon:
1. All of the Directors nominated by Constellation Energy Group were selected
as follows:
COMMON SHARES CAST:
-------------------
For Against Abstain
--- ------- -------
Douglas L. Becker 115,808,626 17,076,048 2,222,777
J. Owen Cole 131,949,012 935,662 2,222,777
Dan A. Colussy 132,035,908 848,766 2,222,777
Edward A. Crooke 131,877,340 1,007,334 2,222,777
Michael D. Sullivan 131,539,851 1,344,823 2,222,777
All other directors whose term of office continues as of the date of this
meeting:
H. Furlong Baldwin
James T. Brady
Beverly B. Byron
James R. Curtiss
Roger W. Gale
Jerome W. Geckle
Dr. Freeman A. Hrabowski, III
Nancy Lampton
Adm. Charles R. Larson
Christian H. Poindexter
George L. Russell, Jr.
Mayo A. Shattuck, III
2. The ratification of PricewaterhouseCoopers LLP as independent accountants
was approved. With respect to holders of common stock, the number of
affirmative votes cast were 132,931,971, the number of negative votes cast
were 1,170,206, and the number of abstentions were 1,183,430.
3. The shareholder proposal for the adoption and implementation of a policy of
Confidential Voting was defeated. With respect to holders of common stock,
the number of affirmative votes cast were 45,564,679, the number of
negative votes cast were 67,075,547, and the number of abstentions were
4,815,338.
36
Item 5. Other Information
Forward-Looking Statements
- --------------------------
We make statements in this report that are considered forward-looking statements
within the meaning of the Securities Exchange Act of 1934. Sometimes these
statements will contain words such as "believes," "expects," "intends," "plans,"
and other similar words. These statements are not guarantees of our future
performance and are subject to risks, uncertainties and other important factors
that could cause our actual performance or achievements to be materially
different from those we project. These risks, uncertainties, and factors
include, but are not limited to:
o 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,
including the outcome of MAPSA's appeal as discussed on page 35,
o commodity price risk,
o operating our generation assets in a deregulated market without the benefit
of a fuel rate adjustment clause,
o loss of revenue due to customers choosing alternative suppliers,
o higher volatility of earnings and cash flows,
o increased financial requirements of our nonregulated subsidiaries,
o inability to recover all costs associated with providing electric retail
customers service during the electric rate freeze period, and
o implications from the transfer of BGE's generation assets and related
liabilities to nonregulated subsidiaries of Constellation Energy, including
the outcome of an appeal of the Maryland PSC's Order regarding the transfer
of generation assets.
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.
37
Item 6. Exhibits and Reports on Form 8-K
(a) * Exhibit No. 2(a) Agreement and Plan of Reorganization and Corporate
Separation (Nuclear). (Designated as Exhibit No.
2(a) in Form 8-K dated July 7, 2000, File Nos.
1-12869 and 1-1910.)
* Exhibit No. 2(b) Agreement and Plan of Reorganization and Corporate
Separation Fossil). (Designated as Exhibit No. 2(b)
in Form 8-K dated July 7, 2000, File Nos. 1-12869
and 1-1910.)
Exhibit 10(a) Full Requirements Service Agreement Between
Constellation Power Source, Inc. and Baltimore Gas
and Electric Company.
Exhibit 10(b) Constellation Energy Group, Inc. Benefits
Restoration Plan.
Exhibit 10(c) Constellation Energy Group, Inc. Supplemental
Pension Plan.
Exhibit 10(d) Constellation Energy Group, Inc. Senior Executive
Supplemental Plan.
Exhibit 10(e) Constellation Energy Group, Inc. Supplemental
Benefits Plan.
Exhibit No. 12(a) Constellation Energy Group, Inc. Computation of
Ratio of Earnings to Fixed Charges.
Exhibit No. 12(b) Baltimore Gas and Electric Company Computation of
Ratio of Earnings to Fixed Charges and Computation
of Ratio of Earnings to Combined Fixed Charges and
Preferred and Preference Dividend Requirements.
Exhibit No. 27(a) Constellation Energy Group, Inc. Financial Data
Schedule.
Exhibit No. 27(b) Baltimore Gas and Electric Company Financial Data
Schedule.
Exhibit No. 99 BGE Pro Forma Financial Statements - Generation
Asset Transfer.
(b) Reports on Form 8-K for the quarter ended June 30, 2000:
None.
------------
* Incorporated by Reference
38
SIGNATURE
---------------------------
Pursuant to the requirements of the Securities Exchange Act of 1934, each
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
CONSTELLATION ENERGY GROUP, INC.
--------------------------------
(Registrant)
BALTIMORE GAS AND ELECTRIC COMPANY
----------------------------------
(Registrant)
Date: August 14, 2000 /s/ D. A. Brune
--------------- ---------------------------------------------
D. A. Brune, Vice President on behalf of each
Registrant and as Principal Financial Officer
of each Registrant
39