UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For The Quarterly Period Ended JUNE 30, 2001
Commission File Exact name of registrant IRS Employer
Number as specified in its charter Identification No.
------ ---------------------------------- -------------------
1-12869 CONSTELLATION ENERGY GROUP, INC. 52-1964611
1-1910 BALTIMORE GAS AND ELECTRIC COMPANY 52-0280210
MARYLAND
-----------------------------------
(State of Incorporation)
250 W. PRATT STREET, BALTIMORE, MARYLAND 21201
------------------------- ---------------------------- -----
(Address of principal executive offices) (Zip Code)
410-234-5000
(Registrants' telephone number, including area code)
NOT APPLICABLE
------------------------------------------------------------------------------
(Former name, former address
and former fiscal year, if changed since last report)
Indicate by check mark whether the registrants (1) have filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months, and (2) have been subject to such filing
requirements for the past 90 days.
Yes X No
---------- ------------
Common Stock, without par value 163,707,950 shares outstanding of Constellation
Energy Group, Inc. on July 31, 2001.
TABLE OF CONTENTS
Page
----
Part I -- Financial Information
Item 1 -- Financial Statements
Constellation Energy Group, Inc. and Subsidiaries
Consolidated Statements of Income...................................................... 3
Consolidated Statements of Comprehensive Income........................................ 3
Consolidated Balance Sheets............................................................ 4
Consolidated Statements of Cash Flows.................................................. 6
Baltimore Gas and Electric Company and Subsidiaries
Consolidated Statements of Income...................................................... 7
Consolidated Balance Sheets............................................................ 8
Consolidated Statements of Cash Flows.................................................. 10
Notes to Consolidated Financial Statements............................................. 11
Item 2 -- Management's Discussion and Analysis of Financial Condition and
Results of Operations
Introduction........................................................................... 18
Strategy............................................................................... 19
Current Issues......................................................................... 20
Results of Operations.................................................................. 24
Financial Condition.................................................................... 31
Capital Resources...................................................................... 32
Other Matters.......................................................................... 34
Item 3 -- Quantitative and Qualitative Disclosures About Market Risk............................. 34
Part II -- Other Information
Item 1 -- Legal Proceedings...................................................................... 35
Item 4 -- Submission of Matters to a Vote of Security Holders.................................... 36
Item 5 -- Other Information...................................................................... 37
Item 6 -- Exhibits and Reports on Form 8-K....................................................... 37
Signature........................................................................................ 38
2
CONSTELLATION ENERGY GROUP, INC. AND SUBSIDIARIES
PART 1 - FINANCIAL INFORMATION
Item 1 - Financial Statements
Consolidated Statements of Income (Unaudited)
Three Months Ended Six Months Ended
June 30, June 30,
2001 2000 2001 2000
- ------------------------------------------------------------------------------------------------------------------
Revenues (In millions, except per share amounts)
Nonregulated revenues $235.0 $209.7 $ 536.5 $ 484.8
Regulated electric revenues 497.4 565.3 989.6 1,089.7
Regulated gas revenues 109.6 91.6 461.8 286.1
- ------------------------------------------------------------------------------------------------------------------
Total revenues 842.0 866.6 1,987.9 1,860.6
Expenses
Operating expenses 514.7 552.8 1,264.8 1,168.6
Depreciation and amortization 102.0 130.6 205.6 263.1
Taxes other than income taxes 55.5 51.1 113.9 112.3
- ------------------------------------------------------------------------------------------------------------------
Total expenses 672.2 734.5 1,584.3 1,544.0
- ------------------------------------------------------------------------------------------------------------------
Income from Operations 169.8 132.1 403.6 316.6
Other Income 5.4 2.8 5.4 6.0
- ------------------------------------------------------------------------------------------------------------------
Income Before Fixed Charges and Income Taxes 175.2 134.9 409.0 322.6
Fixed Charges
Interest expense (net) 53.7 65.1 116.4 125.4
BGE preference stock dividends 3.3 3.3 6.6 6.6
- ------------------------------------------------------------------------------------------------------------------
Total fixed charges 57.0 68.4 123.0 132.0
- ------------------------------------------------------------------------------------------------------------------
Income Before Income Taxes 118.2 66.5 286.0 190.6
Income Taxes
Current 36.5 45.6 112.4 106.8
Deferred 8.1 (16.6) (1.2) (23.7)
Investment tax credit adjustments (2.0) (2.1) (4.1) (4.2)
- ------------------------------------------------------------------------------------------------------------------
Total income taxes 42.6 26.9 107.1 78.9
- ------------------------------------------------------------------------------------------------------------------
Income Before Cumulative Effect of
Change in Accounting Principle $ 75.6 $ 39.6 $ 178.9 $ 111.7
Cumulative Effect of Change in Accounting Principle,
Net of Income Taxes of $5.6 -- -- 8.5 --
- ------------------------------------------------------------------------------------------------------------------
Net Income $ 75.6 $ 39.6 $ 187.4 $ 111.7
- ------------------------------------------------------------------------------------------------------------------
Earnings Applicable to Common Stock $ 75.6 $ 39.6 $ 187.4 $ 111.7
==================================================================================================================
Average Shares of Common Stock Outstanding 163.7 149.7 157.8 149.6
Earnings Per Common Share and Earnings Per
Common Share - Assuming Dilution Before
Cumulative Effect of Change in Accounting Principle $ 0.46 $ 0.26 $ 1.13 $ 0.75
Cumulative Effect of Change in Accounting Principle -- -- .06 --
- ------------------------------------------------------------------------------------------------------------------
Earnings Per Common Share and
Earnings Per Common Share - Assuming Dilution $ 0.46 $ 0.26 $ 1.19 $ 0.75
Dividends Declared Per Common Share $ 0.12 $ 0.42 $ 0.24 $ 0.84
Consolidated Statements of Comprehensive Income (Unaudited)
Three Months Ended Six Months Ended
June 30, June 30,
2001 2000 2001 2000
- ------------------------------------------------------------------------------------------------------------------
(In millions)
Net Income $ 75.6 $ 39.6 $187.4 $111.7
Other comprehensive income, net of taxes 193.6 11.1 179.3 24.1
- ------------------------------------------------------------------------------------------------------------------
Comprehensive Income Before Cumulative Effect of
Change in Accounting Principle 269.2 50.7 366.7 135.8
Cumulative Effect of Change in Accounting Principle,
Net of Income Taxes of $22.6 -- -- (35.5) --
- ------------------------------------------------------------------------------------------------------------------
Comprehensive Income $269.2 $ 50.7 $331.2 $135.8
==================================================================================================================
See Notes to Consolidated Financial Statements.
Certain prior-period amounts have been reclassified to conform with the current
period's presentation.
3
CONSTELLATION ENERGY GROUP, INC. AND SUBSIDIARIES
PART 1 - FINANCIAL INFORMATION (CONTINUED)
Item 1 - Financial Statements
Consolidated Balance Sheets
June 30, December 31,
2001* 2000
- ----------------------------------------------------------------------------------------------------------------------
(In millions)
Assets
Current Assets
Cash and cash equivalents $ 111.8 $ 182.7
Accounts receivable (net of allowance for uncollectibles
of $22.5 and $21.3 respectively) 683.8 738.5
Trading securities 201.9 189.3
Assets from energy trading activities 3,005.6 2,793.0
Fuel stocks 91.6 78.2
Materials and supplies 159.6 151.3
Prepaid taxes other than income taxes 4.1 73.5
Other 48.6 32.7
- ----------------------------------------------------------------------------------------------------------------------
Total current assets 4,307.0 4,239.2
- ----------------------------------------------------------------------------------------------------------------------
Investments and Other Assets
Real estate projects and investments 287.3 290.3
Investments in power projects 517.6 517.5
Financial investments 98.9 161.0
Nuclear decommissioning trust fund 241.5 228.7
Net pension asset 107.3 93.2
Investment in Orion Power Holdings, Inc. 406.2 192.0
Other 131.2 123.0
- ----------------------------------------------------------------------------------------------------------------------
Total investments and other assets 1,790.0 1,605.7
- ----------------------------------------------------------------------------------------------------------------------
Property, Plant and Equipment
Regulated property, plant and equipment 4,873.8 4,860.1
Nonregulated generation property, plant and equipment 5,755.7 5,279.9
Other nonregulated property, plant and equipment 197.0 173.8
Nuclear fuel (net of amortization) 108.5 128.3
Accumulated depreciation (3,860.6) (3,798.1)
- ----------------------------------------------------------------------------------------------------------------------
Net property, plant and equipment 7,074.4 6,644.0
- ----------------------------------------------------------------------------------------------------------------------
Deferred Charges
Regulatory assets (net) 444.6 514.9
Other 120.6 117.3
- ----------------------------------------------------------------------------------------------------------------------
Total deferred charges 565.2 632.2
- ----------------------------------------------------------------------------------------------------------------------
Total Assets $13,736.6 $13,121.1
======================================================================================================================
* Unaudited
See Notes to Consolidated Financial Statements.
Certain prior-period amounts have been reclassified to conform with the current
period's presentation.
4
CONSTELLATION ENERGY GROUP, INC. AND SUBSIDIARIES
PART 1 - FINANCIAL INFORMATION (CONTINUED)
Item 1 - Financial Statements
Consolidated Balance Sheets
June 30, December 31,
2001* 2000
- ----------------------------------------------------------------------------------------------------------------------
(In millions)
Liabilities and Capitalization
Current Liabilities
Short-term borrowings $ 310.2 $ 243.6
Current portions of long-term debt 1,215.8 906.6
Accounts payable 640.0 695.9
Liabilities from energy trading activities 2,428.1 2,323.3
Dividends declared 23.0 66.5
Other 196.0 250.8
- ----------------------------------------------------------------------------------------------------------------------
Total current liabilities 4,813.1 4,486.7
- ----------------------------------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities
Deferred income taxes 1,456.5 1,339.5
Postretirement and postemployment benefits 280.6 265.2
Deferred investment tax credits 97.4 101.4
Other 345.0 426.0
- ----------------------------------------------------------------------------------------------------------------------
Total deferred credits and other liabilities 2,179.5 2,132.1
- ----------------------------------------------------------------------------------------------------------------------
Long-term Debt
Long-term debt of Constellation Energy 1,135.0 1,000.0
Long-term debt of nonregulated businesses 360.2 670.0
First refunding mortgage bonds of BGE 1,174.7 1,174.7
Other long-term debt of BGE 889.6 976.6
Company obligated mandatorily redeemable trust preferred
securities of subsidiary trust holding solely 7.16% debentures
of BGE due June 30, 2038 250.0 250.0
Unamortized discount and premium (4.7) (5.4)
Current portion of long-term debt (1,215.8) (906.6)
- ----------------------------------------------------------------------------------------------------------------------
Total long-term debt 2,589.0 3,159.3
- ----------------------------------------------------------------------------------------------------------------------
BGE Preference Stock Not Subject to Mandatory Redemption 190.0 190.0
Common Shareholders' Equity
Common stock 2,049.5 1,538.7
Retained earnings 1,749.7 1,592.3
Accumulated other comprehensive income 165.8 22.0
- ----------------------------------------------------------------------------------------------------------------------
Total common shareholders' equity 3,965.0 3,153.0
- ----------------------------------------------------------------------------------------------------------------------
Total capitalization 6,744.0 6,502.3
- ----------------------------------------------------------------------------------------------------------------------
Total Liabilities and Capitalization $13,736.6 $13,121.1
======================================================================================================================
* Unaudited
See Notes to Consolidated Financial Statements.
Certain prior-period amounts have been reclassified to conform with the current
period's presentation.
5
CONSTELLATION ENERGY GROUP, INC. AND SUBSIDIARIES
PART 1 - FINANCIAL INFORMATION (CONTINUED)
Item 1 - Financial Statements
Consolidated Statements of Cash Flows (Unaudited)
Six Months Ended June 30,
- ----------------------------------------------------------------------------------------------------------------------
2001 2000
(In millions)
Cash Flows From Operating Activities
Net income $ 187.4 $111.7
Adjustments to reconcile to net cash provided by operating activities
Cumulative effect of change in accounting principle (8.5) --
Depreciation and amortization 227.6 288.2
Deferred income taxes (1.2) (23.7)
Investment tax credit adjustments (4.1) (4.2)
Deferred fuel costs 42.8 9.8
Accrued pension and postemployment benefits 14.0 12.1
Gains on sale of investments and subsidiaries (35.7) (14.3)
Deregulation transition cost -- 24.0
Equity in earnings of affiliates and joint ventures (net) (14.2) 5.3
Changes in assets from energy trading activities (212.6) (767.2)
Changes in liabilities from energy trading activities 104.8 671.0
Changes in other current assets 94.0 59.8
Changes in other current liabilities (99.0) (1.3)
Other (34.3) (28.9)
- ----------------------------------------------------------------------------------------------------------------------
Net cash provided by operating activities 261.0 342.3
- ----------------------------------------------------------------------------------------------------------------------
Cash Flows From Investing Activities
Purchases of property, plant and equipment and other capital expenditures (669.6) (360.7)
Sale of (investment in) Orion 26.2 (101.5)
Contributions to nuclear decommissioning trust fund (13.2) (8.8)
Purchases of marketable equity securities (23.7) (2.4)
Sales of marketable equity securities 70.9 14.4
Other investments 40.9 0.9
- ----------------------------------------------------------------------------------------------------------------------
Net cash used in investing activities (568.5) (458.1)
- ----------------------------------------------------------------------------------------------------------------------
Cash Flows From Financing Activities
Net issuance (maturity) of short-term borrowings 66.6 (156.7)
Proceeds from issuance of
Long-term debt 844.6 800.1
Common stock 504.4 6.0
Reacquisition of long-term debt (1,106.6) (347.7)
Common stock dividends paid (81.4) (125.6)
Other 9.0 (6.6)
- ----------------------------------------------------------------------------------------------------------------------
Net cash provided by financing activities 236.6 169.5
- ----------------------------------------------------------------------------------------------------------------------
Net (Decrease) Increase in Cash and Cash Equivalents (70.9) 53.7
Cash and Cash Equivalents at Beginning of Period 182.7 92.7
- ----------------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of Period $ 111.8 $146.4
======================================================================================================================
Other Cash Flow Information Cash paid during the period for:
Interest (net of amounts capitalized) $116.9 $131.5
Income taxes $133.5 $110.9
See Notes to Consolidated Financial Statements.
Certain prior-period amounts have been reclassified to conform with the current
period's presentation.
6
BALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARIES
PART 1 - FINANCIAL INFORMATION
Item 1 - Financial Statements
Consolidated Statements of Income (Unaudited)
Three Months Ended Six Months Ended
June 30, June 30,
2001 2000 2001 2000
- ----------------------------------------------------------------------------------------------------------------------
(In millions)
Revenues
Electric revenues $497.5 $565.4 $ 989.8 $1,090.0
Gas revenues 109.7 92.7 467.3 287.8
- ----------------------------------------------------------------------------------------------------------------------
Total revenues 607.2 658.1 1,457.1 1,377.8
Expenses
Operating expenses:
Electric fuel and purchased energy 293.9 124.7 559.7 244.1
Gas purchased for resale 52.2 40.9 305.1 143.8
Operations and maintenance 87.2 191.9 173.6 369.5
Depreciation and amortization 55.6 123.2 113.3 248.9
Taxes other than income taxes 43.3 50.4 89.3 110.5
- ----------------------------------------------------------------------------------------------------------------------
Total expenses 532.2 531.1 1,241.0 1,116.8
- ----------------------------------------------------------------------------------------------------------------------
Income from Operations 75.0 127.0 216.1 261.0
Other Income/(Expense) 1.2 1.6 (1.0) 4.4
- ----------------------------------------------------------------------------------------------------------------------
Income Before Fixed Charges and Income Taxes 76.2 128.6 215.1 265.4
Fixed Charges
Interest expense (net) 39.2 47.8 81.5 96.1
Allowance for borrowed funds used during construction (1.1) (1.4) (1.4) (2.6)
- ----------------------------------------------------------------------------------------------------------------------
Total fixed charges 38.1 46.4 80.1 93.5
- ----------------------------------------------------------------------------------------------------------------------
Income Before Income Taxes 38.1 82.2 135.0 171.9
Income Taxes
Current 19.5 44.0 60.3 101.8
Deferred (4.0) (12.2) (5.7) (32.4)
Investment tax credit adjustments (0.6) (2.0) (1.2) (4.1)
- ----------------------------------------------------------------------------------------------------------------------
Total income taxes 14.9 29.8 53.4 65.3
- ----------------------------------------------------------------------------------------------------------------------
Net Income 23.2 52.4 81.6 106.6
Preference Stock Dividends 3.3 3.3 6.6 6.6
- ----------------------------------------------------------------------------------------------------------------------
Earnings Applicable to Common Stock $ 19.9 $ 49.1 $ 75.0 $ 100.0
======================================================================================================================
See Notes to Consolidated Financial Statements.
Certain prior-period amounts have been reclassified to conform with the current
period's presentation.
7
BALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARIES
PART 1 - FINANCIAL INFORMATION (CONTINUED)
Item 1 - Financial Statements
Consolidated Balance Sheets
June 30, December 31,
2001* 2000
- ----------------------------------------------------------------------------------------------------------------------
(In millions)
Assets
Current Assets
Cash and cash equivalents $ 40.2 $ 21.3
Accounts receivable (net of allowance for uncollectibles
of $13.4 and $13.4 respectively) 367.6 413.0
Accounts receivable, affiliated companies 298.7 133.2
Note receivable, affiliated company -- 87.0
Fuel stocks 46.1 34.1
Materials and supplies 37.5 37.3
Prepaid taxes other than income taxes 1.7 44.9
Other 6.7 4.7
- ----------------------------------------------------------------------------------------------------------------------
Total current assets 798.5 775.5
- ----------------------------------------------------------------------------------------------------------------------
Other Assets
Net pension asset 106.0 100.2
Other 72.7 68.7
- ----------------------------------------------------------------------------------------------------------------------
Other assets 178.7 168.9
- ----------------------------------------------------------------------------------------------------------------------
Utility Plant
Plant in service
Electric 3,306.7 3,259.0
Gas 998.7 988.4
Common 477.6 532.9
- ----------------------------------------------------------------------------------------------------------------------
Total plant in service 4,783.0 4,780.3
Accumulated depreciation (1,697.8) (1,700.3)
- ----------------------------------------------------------------------------------------------------------------------
Net plant in service 3,085.2 3,080.0
Construction work in progress 86.3 75.3
Plant held for future use 4.5 4.5
- ----------------------------------------------------------------------------------------------------------------------
Net utility plant 3,176.0 3,159.8
- ----------------------------------------------------------------------------------------------------------------------
Deferred Charges
Regulatory assets (net) 444.6 514.9
Other 33.4 35.1
- ----------------------------------------------------------------------------------------------------------------------
Total deferred charges 478.0 550.0
- ----------------------------------------------------------------------------------------------------------------------
Total Assets $4,631.2 $4,654.2
======================================================================================================================
* Unaudited
See Notes to Consolidated Financial Statements.
8
BALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARIES
PART 1 - FINANCIAL INFORMATION (CONTINUED)
Item 1 - Financial Statements
Consolidated Balance Sheets
June 30, December 31,
2001* 2000
- ----------------------------------------------------------------------------------------------------------------------
(In millions)
Liabilities and Capitalization
Current Liabilities
Short-term borrowings $ -- $ 32.1
Current portions of long-term debt 551.7 567.6
Accounts payable 84.1 119.3
Accounts payable, affiliated companies 171.6 103.5
Customer deposits 47.1 44.4
Accrued taxes 18.6 25.0
Accrued interest 47.8 43.4
Accrued vacation costs 21.6 20.8
Other 17.5 29.6
- ----------------------------------------------------------------------------------------------------------------------
Total current liabilities 960.0 985.7
- ----------------------------------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities
Deferred income taxes 497.2 508.7
Postretirement and postemployment benefits 241.2 231.2
Deferred investment tax credits 23.8 25.0
Decommissioning of federal uranium enrichment facilities 23.7 23.7
Other 21.7 23.2
- ----------------------------------------------------------------------------------------------------------------------
Total deferred credits and other liabilities 807.6 811.8
- ----------------------------------------------------------------------------------------------------------------------
Long-term Debt
First refunding mortgage bonds of BGE 1,174.7 1,174.7
Other long-term debt of BGE 889.6 976.6
Company obligated mandatorily redeemable trust preferred
securities of subsidiary trust holding solely 7.16% debentures
of BGE due June 30, 2038 250.0 250.0
Long-term debt of nonregulated businesses 41.0 34.0
Unamortized discount and premium (2.5) (3.3)
Current portion of long-term debt (551.7) (567.6)
- ----------------------------------------------------------------------------------------------------------------------
Total long-term debt 1,801.1 1,864.4
- ----------------------------------------------------------------------------------------------------------------------
Preference Stock Not Subject to Mandatory Redemption 190.0 190.0
Common Shareholder's Equity
Common stock 462.4 465.1
Retained earnings 410.1 337.2
- ----------------------------------------------------------------------------------------------------------------------
Total common shareholder's equity 872.5 802.3
- ----------------------------------------------------------------------------------------------------------------------
Total capitalization 2,863.6 2,856.7
- ----------------------------------------------------------------------------------------------------------------------
Total Liabilities and Capitalization $4,631.2 $4,654.2
======================================================================================================================
* Unaudited
See Notes to Consolidated Financial Statements.
9
BALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARIES
PART 1 - FINANCIAL INFORMATION (CONTINUED)
Item 1 - Financial Statements
Consolidated Statements of Cash Flows (Unaudited)
Six Months Ended June 30,
2001 2000
- ----------------------------------------------------------------------------------------------------------------------
(In millions)
Cash Flows From Operating Activities
Net income $ 81.6 $106.6
Adjustments to reconcile to net cash provided by operating activities
Depreciation and amortization 114.4 272.9
Deferred income taxes (5.7) (32.4)
Investment tax credit adjustments (1.2) (4.1)
Deferred fuel costs 42.8 9.8
Accrued pension and postemployment benefits 5.8 12.0
Allowance for equity funds used during construction (1.4) (1.6)
Changes in other current assets (91.7) 42.5
Changes in other current liabilities 24.2 (22.5)
Other 13.0 8.8
- ----------------------------------------------------------------------------------------------------------------------
Net cash provided by operating activities 181.8 392.0
- ----------------------------------------------------------------------------------------------------------------------
Cash Flows From Investing Activities
Utility construction expenditures (excluding AFC) (121.3) (176.7)
Nuclear fuel expenditures -- (39.5)
Deferred conservation expenditures (0.3) (0.3)
Contributions to nuclear decommissioning trust fund -- (8.8)
Other (9.5) (3.9)
- ----------------------------------------------------------------------------------------------------------------------
Net cash used in investing activities (131.1) (229.2)
- ----------------------------------------------------------------------------------------------------------------------
Cash Flows From Financing Activities
Net (maturity)/issuance of short-term borrowings (32.1) 70.3
Proceeds from issuance of long-term debt 206.9 -
Reacquisition of long-term debt (200.0) (107.5)
Preference stock dividends paid (6.6) (6.6)
Distributions to Constellation Energy -- (125.6)
Other -- 1.8
- ----------------------------------------------------------------------------------------------------------------------
Net cash used in financing activities (31.8) (167.6)
- ----------------------------------------------------------------------------------------------------------------------
Net Increase (Decrease) in Cash and Cash Equivalents 18.9 (4.8)
Cash and Cash Equivalents at Beginning of Period 21.3 23.5
- ----------------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of Period $ 40.2 $ 18.7
======================================================================================================================
Other Cash Flow Information Cash paid during the period for:
Interest (net of amounts capitalized) $78.2 $ 94.2
Income taxes $64.5 $113.1
See Notes to Consolidated Financial Statements.
Certain prior-period amounts have been reclassified to conform with the current
period's presentation.
10
Notes to Consolidated Financial Statements
- ------------------------------------------
Weather conditions can have a great impact on our results for interim periods.
This means that results for interim periods do not necessarily represent results
to be expected for the year.
Our interim financial statements on the previous pages reflect all
adjustments that Management believes are necessary for the fair presentation of
the financial position and results of operations for the interim periods
presented. These adjustments are of a normal recurring nature.
Holding Company Formation
- -------------------------
On April 30, 1999, Constellation Energy(R) Group, Inc. (Constellation Energy)
became the holding company for Baltimore Gas and Electric Company (BGE(R)) and
its subsidiaries. BGE's outstanding common stock automatically became shares of
common stock of Constellation Energy. BGE's debt securities, obligated
mandatorily redeemable trust preferred securities, and preference stock remain
securities of BGE, or its subsidiaries.
Basis of Presentation
- ---------------------
This Quarterly Report on Form 10-Q is a combined report of Constellation Energy
and BGE. The consolidated financial statements of Constellation Energy include
the accounts of Constellation Energy, BGE and its subsidiaries, Constellation
Enterprises, Inc. and its subsidiaries, and Constellation Nuclear, LLC and its
subsidiaries. The consolidated financial statements of BGE include the accounts
of BGE, District Chilled Water General Partnership (ComfortLink), and BGE
Capital Trust I.
References in this report to "we" and "our" are to Constellation Energy and
its subsidiaries, collectively. Reference in this report to the "utility
business" is to BGE.
Deregulation of Electric Generation
- -----------------------------------
On April 8, 1999, Maryland enacted legislation authorizing customer choice and
competition among electric suppliers. In addition, on November 10, 1999, the
Maryland Public Service Commission (Maryland PSC) issued a Restructuring Order
that resolved the major issues surrounding electric restructuring. Effective
July 1, 2000, the state of Maryland implemented customer choice for electric
suppliers. We discuss the implications of customer choice and the Restructuring
Order further in Management's Discussion and Analysis beginning on page 18.
Please also refer to the Legal Proceedings section on page 35 for a discussion
regarding an appeal of the Restructuring Order.
- --------------------------------------------------------------------------------
Information by Operating Segment
- --------------------------------
Our reportable operating segments are - Domestic Merchant Energy, Regulated
Electric, and Regulated Gas:
o Our nonregulated domestic merchant energy business:
- provides power marketing, and risk management services,
- develops, owns, and operates domestic power
projects, and
- provides nuclear consulting services.
o Our regulated electric business purchases, distributes and sells
electricity, and
o Our regulated gas business purchases, transports, and sells natural gas.
Effective July 1, 2000, the financial results of the electric generation
portion of our business are included in the domestic merchant energy business
segment. Prior to that date, the financial results of electric generation are
included in our regulated electric business.
Our remaining nonregulated businesses:
o develop, own, and operate international power projects in Latin America,
o provide energy products and services,
o sell and service electric and gas appliances, and heating and air
conditioning systems, engage in home improvements, and sell natural gas
through mass marketing efforts,
o provide cooling services,
o engage in financial investments, and
o develop, own and manage real estate and senior-living facilities.
These reportable segments are strategic businesses based principally upon
regulations, products, and services that require different technology and
marketing strategies. We evaluate the performance of these segments based on net
income. We account for intersegment revenues using market prices.
11
Domestic Unallocated
Merchant Regulated Regulated Other Corporate
Energy Electric Gas Nonregulated Items and
Business Business Business Businesses Eliminations Consolidated
- --------------------------- -------------- -------------- --------------- ------------- -------------- ------------
For the three months ended June 30, (In millions)
2001
- ----
Unaffiliated revenues $ 90.8 $ 497.4 $109.6 $144.2 $ -- $ 842.0
Intersegment revenues 281.7 0.1 0.1 0.8 (282.7) --
- ---------------------------- ------------- -------------- --------------- ------------- ------------ --------------
Total revenues 372.5 497.5 109.7 145.0 (282.7) 842.0
Net income 52.4 18.0 3.0 2.2 -- 75.6
2000
- ----
Unaffiliated revenues $ 64.1 $ 565.3 $ 91.6 $145.6 $ -- $ 866.6
Intersegment revenues -- 0.1 1.1 -- (1.2) --
- ---------------------------- ------------- -------------- --------------- ------------- ------------ --------------
Total revenues 64.1 565.4 92.7 145.6 (1.2) 866.6
Net income (a) 1.9 47.3 2.3 (11.9) -- 39.6
For the six months ended June 30,
2001
- ----
Unaffiliated revenues $176.7 $ 989.6 $461.8 $359.8 $ -- $1,987.9
Intersegment revenues 532.5 0.2 5.5 1.9 (540.1) --
- ---------------------------- ------------- -------------- --------------- ------------- ------------ --------------
Total revenues 709.2 989.8 467.3 361.7 (540.1) 1,987.9
Cumulative effect of change
in accounting principle -- -- -- 8.5 -- 8.5
Net income 94.8 45.7 31.7 15.2 -- 187.4
2000
- ----
Unaffiliated revenues $133.4 $1,089.7 $286.1 $351.4 $ -- $1,860.6
Intersegment revenues -- 0.3 1.7 6.7 (8.7) --
- ---------------------------- ------------- -------------- --------------- ------------- ------------ --------------
Total revenues 133.4 1,090.0 287.8 358.1 (8.7) 1,860.6
Net income (a) 20.1 78.1 22.6 (9.1) -- 111.7
At June 30, 2001
- ----------------
Segment assets $8,068.8 $3,472.3 $1,104.3 $1,475.8 $(384.6) $13,736.6
At December 31, 2000
- --------------------
Segment assets $7,297.8 $3,392.3 $1,089.9 $1,491.5 $(150.4) $13,121.1
(a) Our regulated electric business recorded an expense of $1.7 million for the
quarter ended and $4.2 million for the six months ended related to
employees that elected to participate in a Targeted Voluntary Special Early
Retirement Program. In addition, our domestic merchant energy business
recorded a $15.0 million deregulation transition cost incurred by our power
marketing operation.
Certain prior-period amounts have been reclassified to conform with the current
period's presentation.
12
Financing Activity
- ------------------
Constellation Energy
- --------------------
As discussed on page 11, effective April 30, 1999, BGE's outstanding common
stock automatically became shares of common stock of Constellation Energy.
During the period from January 1, 2001 through the date of this report, we
issued a total of 13.2 million shares of common stock, without par value for net
proceeds of $504.4 million. We issued 12.0 million shares through a secondary
offering and the remaining 1.2 million shares were issued under our Continuous
Offering Program for Stock and the Shareholder Investment Plan.
Constellation Energy issued and redeemed prior to their maturity the
following notes during the period from January 1, 2001 through the date of this
report:
Date Net
Issued/ Proceeds/
Principal Redeemed Payments
- ---------------------------- --------- -------- --------
(In millions)
Issued:
- -------
Floating Rate Notes due 2002 $400.0 1/01 $399.7
Floating Rate Notes due 2002 235.0 4/01 234.7
Redeemed:
- ---------
Floating Rate Reset Notes
due 2002 $200.0 1/01 $200.0
Extendible Notes due 2010 300.0 6/01 300.0
In connection with the initiative to separate our domestic merchant energy
business from our retail services business, Constellation Energy expects to
redeem all of its outstanding long-term debt at or prior to the separation
(approximately $1.1 billion currently) and to repay any outstanding commercial
paper borrowings at that time. The redemption will occur through a combination
of open market purchases, tender offers, and redemption calls.
In June 2001, Constellation Energy arranged a $2.5 billion revolving credit
facility. This facility will be used primarily to fund capital expenditures, and
working capital requirements, including commercial paper support, for the
domestic merchant energy business, to redeem the $1.1 billion of its outstanding
long-term debt, and to repay commercial paper borrowings. Prior to or upon
separation, the new merchant energy company will assume this facility and
expects to refinance the facility shortly thereafter.
In June 2001, Constellation Energy also arranged a $380 million
revolving credit facility to be used primarily to support letters of credit and
for other short-term financing needs. Prior to or upon separation, the new
merchant energy company also will assume this facility.
We discuss the separation of our businesses in the Strategy section of
Management's Discussion and Analysis on page 19.
Constellation Energy also has an existing $188.5 million revolving credit
facility available for short-term and long-term needs, including letters of
credit. Upon separation, this facility will either be terminated or assumed by
the new merchant energy company.
As of the date of this report, letters of credit that totaled $178.4 million
were issued under all of our facilities.
Constellation Energy has issued guarantees in an amount up to $1.3 billion
primarily related to credit facilities and contractual performance of our
domestic merchant energy business. However, the actual subsidiary liabilities
related to these guarantees totaled $167.1 million at June 30, 2001. In
connection with the separation, the domestic merchant energy guarantees will be
replaced by guarantees, letters of credit, or other types of collateral of the
new merchant energy company.
BGE and Nonregulated Businesses
- -------------------------------
BGE issued and redeemed prior to their maturity the following notes during the
period from January 1, 2001 through the date of this report:
Date Net
Issued/ Proceeds/
Principal Redeemed Payments
- ---------------------------- --------- -------- --------
(In millions)
Issued:
- -------
Floating Rate Notes due 2002 $200.0 5/01 $200.0
Redeemed:
- ---------
Floating Rate Reset Notes
due 2001 $200.0 5/01 $200.0
In conjunction with the July 1, 2000 transfer of generation assets, BGE
currently is contingently liable for $276.3 million of the tax exempt debt that
was assigned to nonregulated affiliates of Constellation Energy as discussed
further in the Current Issues -Electric Competition section of Management's
Discussion and Analysis on page 20. In the future, BGE may purchase some of its
long-term debt or preference stock in the market. This will depend on market
conditions and BGE's capital structure.
Please refer to the Funding for Capital Requirements section of Management's
Discussion and Analysis on page 33 for additional information about the debt of
BGE and our nonregulated businesses.
Commitments
- -----------
Our domestic merchant energy business has committed to contribute additional
capital and to make additional loans to some affiliates, joint ventures, and
partnerships in which they have an interest. At June 30, 2001, the total amount
of investment requirements committed to by our domestic merchant energy business
was $162.6 million.
Environmental Matters
- ---------------------
Clean Air
The Clean Air Act includes two titles designed to reduce emissions of sulfur
dioxide and nitrogen oxide (NOx) from electric generating plants - Title IV and
Title I.
13
Title IV addresses emissions of sulfur dioxides. For our older plants, we
meet the requirements of Title IV through a combination of switching fuels and
allowance trading. For newer plants, we meet the requirements of Title IV
primarily through facility design, and operational and pollution controls.
Title I addresses emissions of NOx. The Environmental Protection Agency
(EPA) issued a final rule in 1998 that required up to 85% NOx emissions
reduction by 22 states (including Maryland and Pennsylvania). Maryland and
Pennsylvania have issued regulations pursuant to EPA's rule. At our Brandon
Shores and Wagner facilities in Maryland, we are installing emission reduction
equipment that will be in operation by May 2002 in order to meet Maryland's
deadline. Emissions reduction equipment will be installed by 2003 at the
Keystone plant in Pennsylvania to meet the Pennsylvania deadline.
We currently estimate that the controls needed at our generating plants to
meet the NOx emission reduction requirements will cost approximately $260
million. Through June 30, 2001, we have spent approximately $167 million to meet
these reduction requirements. Future expenditures for NOx reduction will be paid
by our domestic merchant energy business.
In July 1997, the EPA published new National Ambient Air Quality Standards
for very fine particulates and revised standards for ozone attainment. In 1999,
these new standards were successfully challenged in court. The EPA appealed the
1999 court rulings to the Supreme Court. In February 2001, the Supreme Court
upheld EPA's authority to issue the standards. However, the Supreme Court sent
the case back to the lower court and EPA for further proceedings on
implementation issues related to the revised ozone standard. The lower court
will also address remaining challenges to the fine particulate standard. While
these standards may require increased controls at our fossil generating plants
in the future, implementation, if required, could be delayed for several years.
We cannot estimate the cost of these increased controls at this time because the
states, including Maryland, Pennsylvania, and California, still need to
determine what reductions in pollutants will be necessary to meet the EPA
standards.
In December 2000, the EPA issued a determination that coal-fired power plant
mercury emissions will be controlled. Final regulations are expected to be
issued in 2004 with controls required by 2007.The costs of these controls cannot
be estimated at this time since the level of control or systems to implement
them have not yet been established, but such costs could be material.
We received letters from the EPA requesting us to provide certain
information under Section 114 of the Clean Air Act regarding some of our
electric generating plants in Maryland and Pennsylvania. This information is to
determine compliance with the Clean Air Act and state implementation plan
requirements, including potential application of federal new source performance
standards. In general, such standards can require the installation of additional
air pollution control equipment upon the major modification of an existing
plant. We have provided the EPA the requested information. We believe our
generating plants have been operated in accordance with the Clean Air Act and
the rules implementing this act. However, we cannot estimate the impact of this
inquiry on our generating plants, and our financial results, at this time, but
the impact could be material if the EPA was successful in any action they might
pursue against our facilities.
Waste Disposal
- --------------
The EPA and several state agencies have notified us that we are considered a
potentially responsible party with respect to the cleanup of certain
environmentally contaminated sites owned and operated by others. We cannot
estimate the cleanup costs for all of these sites.
We can, however, estimate that our current 15.47% share of the reasonably
possible cleanup costs at one of these sites, Metal Bank of America, a metal
reclaimer in Philadelphia, could be as much as $2.3 million higher than amounts
we have recorded as a liability on our Consolidated Balance Sheets. This
estimate is based on a Record of Decision issued by the EPA.
Also, we are coordinating investigation of several sites where gas was
manufactured in the past. The investigation of these sites includes reviewing
possible actions to remove coal tar. In late December 1996, we signed a consent
order with the Maryland Department of the Environment (MDE) that requires us to
implement remedial action plans for contamination at and around the Spring
Gardens site, located in Baltimore, Maryland. We submitted the required remedial
action plans and they were approved by the MDE. Based on the remedial action
plans, the costs we consider to be probable to remedy the contamination are
estimated to total $47 million. We have recorded these costs as a liability on
our Consolidated Balance Sheets and have deferred these costs, net of
accumulated amortization and amounts we recovered from insurance companies, as a
regulatory asset. Because of the results of studies at these sites, it is
reasonably possible that these additional costs could exceed the amount we
recognized by approximately $14 million. We discuss this further in Note 5 of
our 2000 Annual Report on Form 10-K. Through June 30, 2001, we have spent
approximately $36 million for remediation at this site.
We do not expect the cleanup costs of the remaining sites to have a material
effect on our financial results.
Other potential environmental liabilities and pending environmental actions
are described further in our 2000 Annual Report on Form 10-K in Item 1. Business
- - Environmental Matters.
14
Nuclear Insurance
- -----------------
If there was an accident or an extended outage at either unit of the Calvert
Cliffs Nuclear Power Plant (Calvert Cliffs), it could have a substantial adverse
financial effect on us. The primary contingencies that would result from an
incident at Calvert Cliffs could include:
o physical damage to the plant,
o recoverability of replacement power costs, and
o our liability to third parties for property damage and bodily injury.
We have insurance policies that cover these contingencies, but the policies
have certain industry standard exclusions. Furthermore, the costs that could
result from a covered major accident or a covered extended outage at either of
the Calvert Cliffs units could exceed our insurance coverage limits.
Insurance for Calvert Cliffs and Third Party Claims
- ---------------------------------------------------
For physical damage to Calvert Cliffs, we have $2.75 billion of property
insurance from an industry mutual insurance company. If an outage at either of
the two units at Calvert Cliffs is caused by an insured physical damage loss and
lasts more than 12 weeks, we have insurance coverage for replacement power costs
up to $490.0 million per unit, provided by an industry mutual insurance company.
This amount can be reduced by up to $98.0 million per unit if an outage at both
units of the plant is caused by a single insured physical damage loss. If
accidents at any insured plants cause a shortfall of funds at the industry
mutual insurance company, all policyholders could be assessed, with our share
being up to $16 million.
In addition we, as well as others, could be charged for a portion of any
third party claims associated with a nuclear incident at any commercial nuclear
power plant in the country. At the date of this report, the limit for third
party claims from a nuclear incident is $9.54 billion under the provisions of
the Price Anderson Act. If third party claims exceed $200 million (the amount of
primary insurance), our share of the total liability for third party claims
could be up to $176.2 million per incident. That amount would be payable at a
rate of $20 million per year.
Insurance for Worker Radiation Claims
- -------------------------------------
As an operator of a commercial nuclear power plant in the United States, we are
required to purchase insurance to cover radiation injury claims of certain
nuclear workers. On January 1, 1998, a new insurance policy became effective for
all operators requiring coverage for current operations. Waiving the right to
make additional claims under the old policy was a condition for acceptance under
the new policy. We describe both the old and new policies below.
o Nuclear worker claims reported on or after January 1, 1998 are covered by
a new insurance policy with an annual industry aggregate limit of $200
million for radiation injury claims against all those insured by this
policy.
o All nuclear worker claims reported prior to January 1, 1998 are still
covered by the old insurance policies. Insureds under the old policies,
with no current operations, are not required to purchase the new policy
described above, and may still make claims against the old policies for
the next seven years. If radiation injury claims under these old policies
exceed the policy reserves, all policyholders could be assessed, with our
share being up to $6.3 million.
If claims under these policies exceed the coverage limits, the provisions of
the Price Anderson Act (discussed in this section) would apply.
Recoverability of Electric Fuel Costs
- -------------------------------------
Under the terms of the Restructuring Order, BGE's electric fuel rate clause was
discontinued effective July 1, 2000. In September 2000, the Maryland PSC
approved the collection of the $54.6 million accumulated difference between our
actual costs of fuel and energy and the amounts collected from customers that
were deferred (included as an asset or liability on the Consolidated Balance
Sheets and excluded from the Consolidated Statements of Income) under the
electric fuel rate clause through June 30, 2000. We are collecting this
accumulated difference from customers over the twelve-month period beginning
October 2000.
California Power Purchase Agreements
- ------------------------------------
Our domestic generation operation has $304.0 million invested in 14 projects
that sell electricity in California under power purchase agreements called
"Interim Standard Offer No. 4" agreements.
Under these agreements, the electricity rates changed from fixed to variable
rates beginning in 1996. In 2000, the last four projects transitioned to
variable rates. In 2001, the prices received under these agreements were higher
than prior periods due to increases in the variable-rate pricing terms. However,
due to the uncertainties in California, the increases in prices may not be
indicative of future prices. We discuss the developments in California in the
Current Issues--Electric Competition section on page 21.
We also describe these projects and the transition process in Note 3 and
Note 10 of our 2000 Annual Report on Form 10-K.
15
Related Party Transactions - BGE
- --------------------------------
Income Statement
- ----------------
Under the Restructuring Order, BGE is providing standard offer service to
customers at fixed rates over various time periods during the transition period
from July 1, 2000 to June 30, 2006, for those customers that do not choose an
alternate supplier. Constellation Power Source is under contract to provide BGE
with the energy and capacity required to meet its standard offer service
obligations for the first three years of the transition period. The cost of
BGE's purchased energy from nonregulated affiliates of Constellation Energy to
meet its standard offer service obligation was $281.2 million for the quarter
and $532.5 million for the six months ended June 30, 2001.
In addition, Constellation Energy charges BGE for certain corporate
functions. Certain costs are directly charged to BGE. We allocate other
corporate function costs based on a total percentage of expected use by BGE.
Management believes this method of allocation is reasonable and approximates the
cost BGE would have incurred as an unaffiliated entity. These costs were $6.1
million for the quarter ended June 30, 2001 compared to $6.1 million for the
same period in 2000 and $10.2 million for the six months ended June 30, 2001
compared to $7.3 million for the same period in 2000.
Balance Sheet
- -------------
As a result of the deregulation of electric generation, BGE transferred its
generation assets to nonregulated affiliates of Constellation Energy effective
July 1, 2000. In conjunction with this transfer, Constellation Power Source
Generation, Inc. issued approximately $366.0 million in unsecured promissory
notes to BGE. All of these notes have been repaid by Constellation Power Source
Generation, Inc. The proceeds were used to service current maturities of certain
BGE long-term debt.
Amounts related to corporate functions performed at the Constellation Energy
holding company, BGE's purchases to meet its standard offer service obligation,
and BGE's charges to Constellation Energy and its nonregulated affiliates for
certain services it provides them result in intercompany balances on BGE's
Consolidated Balance Sheets. Management believes its allocation methods are
reasonable and approximate the costs that would be charged to unaffiliated
entities.
Accounting Standard Adopted
- ---------------------------
On January 1, 2001, we adopted Statement of Financial Accounting Standards
(SFAS) No. 133, Accounting for Derivative Instruments and Hedging
Activities, as amended by SFAS No. 138, Accounting for Certain Derivative
Instruments and Certain Hedging Activities. These statements require that we
recognize all derivatives on the balance sheet at fair value. Changes in the
value of derivatives that are not hedges must be recorded in earnings.
We use derivatives in connection with our power marketing and risk
management activities and to hedge the risk of variations in future cash flows
from forecasted purchases and sales of electricity and gas in our electric
generation operations as more fully described below. Under SFAS No. 133, changes
in the value of derivatives designated as hedges that are effective in
offsetting the variability in cash flows of forecasted transactions are
recognized in other comprehensive income until the forecasted transactions
occur. The ineffective portion of changes in fair value of derivatives used as
cash-flow hedges is immediately recognized in earnings.
In accordance with the transition provisions of SFAS No. 133, we recorded the
following at January 1, 2001:
o an $8.5 million after-tax cumulative effect adjustment that increased
earnings, and
o a $35.5 million after-tax cumulative effect adjustment that reduced
other comprehensive income.
The cumulative effect adjustment recorded in earnings represents the fair
value as of January 1, 2001 of a warrant for 705,900 shares of common stock of
Orion Power Holdings, Inc. (Orion). The warrant has an exercise price of $10 per
share and expires on April 24, 2010. The warrant was received in conjunction
with our investment in Orion. We can exercise the warrant for an equivalent
number of shares of Orion's common stock with the payment of the full exercise
price. We also can exercise the warrant without payment and be entitled to a
number of shares of Orion's common stock equivalent to the difference between
the aggregate current market price less the aggregate exercise price, divided by
the current market price of one share of common stock.
The cumulative effect adjustment recorded in other comprehensive income
represents certain forward sales of electricity that we designated as cash flow
hedges of forecasted transactions primarily through our domestic merchant energy
business. We discuss our risk management for derivatives and hedging activities
below.
Risk Management for Derivatives and Hedging Activities
- ------------------------------------------------------
Our domestic merchant energy business is exposed to market risk from the power
marketing operation of Constellation Power Source and from our electric
generation operations. Constellation Power Source manages the commodity price
risk inherent in its power marketing activities on a portfolio basis, subject to
established trading and risk management policies.
16
Constellation Power Source uses a variety of derivative and non-derivative
instruments, including:
o forward contracts, which commit us to purchase or sell energy commodities
in the future;
o futures contracts, which are exchange-traded standardized commitments to
purchase or sell a commodity or financial instrument, or to make a cash
settlement, at a specific price and future date;
o swap agreements, which require payments to or from counterparties based
upon the differential between two prices for a predetermined contractual
(notional) amount; and
o option contracts, which convey the right to buy or sell a commodity,
financial instrument, or index at a predetermined price.
Our domestic merchant energy business conducts electric generation
operations primarily through Constellation Power Source Generation, Calvert
Cliffs, and Constellation Power. Presently, the majority of the generating
capacity controlled by our domestic merchant energy business is used to
provide standard offer service to BGE. However, beginning in July 2002, we
expect approximately 1,000 megawatts of industrial customer load will leave
BGE's standard offer service. The remainder of our domestic merchant energy
business' standard offer service arrangement with BGE terminates on June
30, 2003. However, BGE has solicited bids for the supply of its standard
offer service from July 1, 2003 through June 30, 2006. Constellation Power
Source submitted a bid. Additionally, we plan to expand our generation
operations. As a result, our domestic merchant energy business has a
substantial and increasing amount of generating capacity that is subject to
future changes in wholesale electricity prices and has fuel requirements
that are subject to future changes in coal, natural gas, and oil prices.
Constellation Power Source manages the commodity price risk of our electric
generation operations as part of its overall portfolio. In order to manage this
risk, we may enter into fixed-price derivative or non-derivative contracts to
hedge the variability in future cash flows from forecasted sales of electricity
and purchases of fuel. Our objectives for entering into such hedges include
fixing the price for a portion of anticipated future electricity sales at a
level that provides an acceptable return on our electric generation operations
and fixing the price of a portion of anticipated fuel purchases for the
operation of our power plants. The portion of forecasted transactions hedged may
vary based upon management's assessment of market, weather, operational, and
other factors.
As of June 30, 2001, our domestic merchant energy business had designated
certain fixed-price forward electricity sale contracts as a cash-flow hedge of
forecasted sales of electricity for the years 2003 through 2010.
At June 30, 2001, we recorded mark-to-market gains of $50.8 million on
derivatives designated as cash-flow hedges in "Accumulated Other Comprehensive
Income" and in "Other Assets" in our Consolidated Balance Sheets. We do not
expect to reclassify any of this amount into earnings during the next twelve
months. For the quarter and six months ended June 30, 2001, there was no hedge
ineffectiveness recognized in earnings. We discuss our market risk in Item 7.
Management's Discussion and Analysis - Market Risk of our 2000 Annual Report on
Form 10-K.
Accounting Standards Issued
- ---------------------------
In July 2001, the FASB issued SFAS No. 141, Business Combinations, SFAS No.
142, Goodwill and Other Intangible Assets, and SFAS No. 143, Accounting for
Obligations Associated with the Retirement of Long-Lived Assets.
SFAS No. 141 requires that all business combinations be accounted for under
the purchase method. Use of the pooling-of-interests method is prohibited for
business combinations initiated after June 30, 2001. This statement also
establishes criteria for the separate recognition of intangible assets acquired
in a business combination.
SFAS No. 142 requires that goodwill no longer be amortized to earnings, but
instead be subject to periodic testing for impairment. This statement is
effective for fiscal years beginning after December 15, 2001, with earlier
application permitted only in specified circumstances.
We do not expect the adoption of these statements to have a material impact
on our financial results.
SFAS No. 143 provides the accounting requirements for asset retirement
obligations associated with tangible long-lived assets. This statement is
effective for fiscal years beginning after June 15, 2002, and early adoption is
permitted. Currently, we are evaluating this statement and have not determined
the impact on our financial results.
Investment in Orion
- -------------------
Effective June 1, 2001, we changed our accounting for the investment in Orion
from the equity method to the cost method, subject to the fair value
requirements of SFAS No. 115, Accounting for Certain Investments in Debt and
Equity Securities. This change resulted from no longer having significant
influence as required under equity method accounting due to a reduction in our
ownership percentage. Our ownership percentage decreased due to Orion's issuance
of 13 million shares of common stock that were sold in a public offering and due
to our sale of one million shares as part of the offering. Under SFAS No. 115,
we classify our investment in Orion as available-for-sale securities and
record any unrealized gains or losses in Accumulated Other Comprehensive Income
on our Consolidated Balance Sheets. At June 30, 2001, the unrealized gain on our
investment in Orion was $124.6 million.
17
Item 2. Management's Discussion
- -------------------------------
Management's Discussion and Analysis of Financial Condition and Results of
- --------------------------------------------------------------------------
Operations
- ----------
Introduction
- ------------
Constellation Energy Group, Inc. (Constellation Energy) is a diversified North
American energy company. Constellation Energy conducts its business through
various subsidiaries that primarily include a domestic merchant energy business
and Baltimore Gas and Electric Company (BGE). Our domestic merchant energy
business is focused mostly on power marketing and merchant generation in North
America. BGE is an electric and gas public utility distribution company with a
service territory that covers the City of Baltimore and all or part of ten
counties in Central Maryland. We describe our operating segments in the Notes to
Consolidated Financial Statements on page 11.
References in this report to "we" and "our" are to Constellation Energy and
its subsidiaries, collectively. Reference in this report to the "utility
business" is to BGE. This Quarterly Report on Form 10-Q is a combined report of
Constellation Energy and BGE.
Effective July 1, 2000, electric generation was deregulated in Maryland.
Also, on July 1, 2000, BGE transferred all of its generation assets and related
liabilities at book value to our domestic merchant energy business. We discuss
the deregulation of electric generation in the Current Issues section on
page 20.
As a result of these changes, our domestic merchant energy business includes
the:
o wholesale power marketing and risk management activities of Constellation
Power Source, Inc.,
o domestic power projects of Constellation Investments, Inc. and
Constellation Power, Inc. and subsidiaries,
o fossil and hydroelectric generating assets of Constellation Power
Source Generation, Inc.,
o nuclear generating assets of Calvert Cliffs Nuclear Power Plant, Inc.,
and
o nuclear consulting services of Constellation Nuclear Services, Inc.
Also, effective July 1, 2000, the financial results of the electric generation
portion of our business are included in the domestic merchant energy business.
Prior to that date, the financial results of electric generation were included
in BGE's regulated electric business.
BGE remains a regulated electric and gas public utility company with a
service territory in the City of Baltimore and all or part of ten counties in
Central Maryland.
Our other nonregulated businesses include the:
o Latin American power projects and investments of Constellation Power and
subsidiaries,
o energy products and services of Constellation Energy Source, Inc.,
o home products, commercial building systems, and residential and
commercial electric and gas retail marketing of BGE Home Products &
Services, Inc. and subsidiaries,
o ComfortLink general partnership, in which BGE is a partner, that provides
cooling services for commercial customers in Baltimore,
o financial investments of Constellation Investments, and
o real estate and senior-living facilities of Constellation Real Estate
Group, Inc.
As discussed further in the Strategy section on page 19, on October 23,
2000, we announced initiatives to separate our domestic merchant energy business
from our remaining businesses. These remaining businesses include BGE and the
other nonregulated businesses described above.
In this discussion and analysis, we explain the general financial condition
and the results of operations for Constellation Energy and BGE including:
o what factors affect our businesses,
o what our earnings and costs were in the periods presented,
o why earnings and costs changed between periods,
o where our earnings came from,
o how all of this affects our overall financial condition,
o what we expect our expenditures for capital projects to be in the future,
and
o where we expect to get cash for future capital expenditures.
As you read this discussion and analysis, refer to our Consolidated
Statements of Income on page 3, which present the results of our operations for
the quarters and six months ended June 30, 2001 and 2000. We analyze and explain
the differences between periods in the specific line items of the Consolidated
Statements of Income. Our analysis is important in making decisions about your
investments in Constellation Energy and/or BGE.
Also, this discussion and analysis is based on the operation of the electric
generation portion of our utility business under rate regulation through June
30, 2000. Our regulated electric business changed as we transferred our electric
generation assets and related liabilities to our domestic merchant energy
business and we entered into retail customer choice for electric generation
effective July 1, 2000. In addition, we announced our intention to separate our
domestic merchant energy business from our remaining businesses. Accordingly,
the results of operations and financial condition described in this discussion
and analysis are not necessarily indicative of future performance.
18
Strategy
- --------
Customer choice and regulatory change significantly impact our business. In
response, we regularly evaluate our strategies with two goals in mind: to
improve our competitive position, and to anticipate and adapt to regulatory
change. Prior to July 1, 2000, the majority of our earnings were from BGE. Going
forward, prior to separating into two companies, we expect to derive almost
two-thirds of our earnings from our domestic merchant energy business.
While BGE continues to be regulated and to deliver electricity and natural
gas through its core distribution business, our primary growth strategies center
on the nonregulated domestic merchant energy business.
On October 23, 2000, we announced three initiatives to advance our growth
strategies. The first initiative is that we entered into an agreement (the
"Agreement") with an affiliate of The Goldman Sachs Group, Inc. ("Goldman
Sachs"). Under the terms of the Agreement, Goldman Sachs will acquire up to a
17.5% equity interest in our domestic merchant energy business, which will be
consolidated under a single holding company ("new Constellation Energy").
Goldman Sachs will also acquire a ten-year warrant for up to 13% of new
Constellation Energy's common stock (subject to certain adjustments). The
warrant is exercisable six months after new Constellation Energy's common stock
becomes publicly available. The amount of common stock which Goldman Sachs may
receive upon exercise will be equal to the excess of the market price of new
Constellation Energy's common stock at the time of exercise over the exercise
price of $60 per share for all the stock subject to the warrant, divided by the
market price. New Constellation Energy may at its option pay Goldman Sachs such
excess in cash. Goldman Sachs is acquiring its interest and the warrant in
exchange for $250 million in cash (subject to adjustment in certain instances)
and certain assets related to our power marketing operation. At closing, Goldman
Sachs' existing services agreement with our power marketing operation will
terminate.
The second initiative is a plan to separate our domestic merchant energy
business from our remaining businesses as discussed in the introduction. The
separation will create two stand-alone, publicly traded energy companies. One
will be a merchant energy business engaged in wholesale power marketing and
generation under the name "Constellation Energy Group" after the separation. The
other will be a regional retail energy delivery and energy services company, BGE
Corp., which will include BGE, our other nonregulated businesses, and our
investment in Orion Power Holdings, Inc. ("Orion").
As a result of the separation, shareholders will continue to own all of
Constellation Energy's current businesses through their ownership of the stock
of the new Constellation Energy Group and of BGE Corp.
The third initiative is a change in our common stock dividend policy
effective April 2001. In a move closely aligned with our separation plan,
effective April 2001, our annual dividend was set at $.48 per share. After the
separation, BGE Corp. expects to pay initial annual dividends of $.48 per share.
Constellation Energy Group, as a growing merchant energy company, initially
expects to reinvest its earnings in order to fund its growth plans and not to
pay a dividend.
The closing of the transaction with Goldman Sachs and the separation are
subject to customary closing conditions and contingent upon obtaining regulatory
approvals and a Private Letter Ruling from the Internal Revenue Service
regarding certain tax matters. We expect to complete the transaction and
separation by late 2001. At the date of this report, we have received approval
from the Federal Energy Regulatory Commission (FERC) and the Nuclear Regulatory
Commission (NRC).
Upon separation, the strategy for the new Constellation Energy is to be a
leading competitive provider of energy solutions for wholesale customers in
North America. To achieve this, new Constellation Energy expects to continue to
expand its marketing and risk management operations supported by geographic,
fuel, and dispatch diversification. In addition, new Constellation Energy
expects to continue to grow its generation business through acquisition,
development, and contractual arrangements.
The primary strategy for BGE Corp. is to expand its core utility and
non-regulated retail energy services businesses throughout surrounding areas.
Currently, our domestic merchant energy business controls over 10,000
megawatts of generation including 1,100 megawatts of natural gas-fired peaking
capacity that commenced operations in the Mid-Atlantic and Mid-West regions
during mid-summer 2001. In December 2000, we announced that a subsidiary of
Constellation Nuclear will purchase 1,550 megawatts of the 1,757 megawatts total
generating capacity of the Nine Mile Point nuclear power plant located in
Scriba, New York. The closing of the Nine Mile Point power plant was expected to
take place by July 1, 2001. The total purchase price based on the expected
closing date, including fuel, was $815 million. However, the closing date has
been delayed as the sellers and New York State regulators work to settle all
remaining stranded cost issues. The contract provides for a reduction in the
purchase price for each day that the closing is delayed beyond the target date
of July 1, 2001. At the date of this report, we have received approval from the
FERC and the NRC. We expect to close on the Nine Mile purchase later this year.
We discuss the planned acquisition of the
19
Nine Mile Point power plant in more detail in Note 10 of our 2000 Annual
Report on Form 10-K.
We also have an additional 6,000 megawatts of natural gas-fired peaking and
combined cycle production facilities in various regions of North America under
construction or in development. We are currently in the process of soliciting
offers to purchase our Latin American operations due to our concentration on
domestic merchant energy. We plan to sell the businesses if offers received are
reasonable relative to the cash flows expected to be earned if we continue to
own the businesses.
We also might consider one or more of the following strategies:
o the complete or partial separation of our transmission and distribution
functions,
o mergers or acquisitions of utility or non-utility businesses, and sale of
o generation assets or one or more businesses.
- --------------------------------------------------------------------------------
Current Issues
- ---------------
With the shift toward customer choice, competition, and the growth of our
domestic merchant energy business, various factors affect our financial results.
We discuss these various factors in the Forward Looking Statements section on
page 37.
In this section, we discuss in more detail several issues that affect our
businesses.
Electric Competition
- --------------------
We are facing electric competition on various fronts, including:
o the construction of generating units to meet increased demand for
electricity,
o the sale of electricity in wholesale power markets,
o competing with other energy suppliers, and
o electric sales to retail customers.
Maryland
- --------
On April 8, 1999, Maryland enacted the Electric Customer Choice and Competition
Act of 1999 (the "Act") and accompanying tax legislation that has significantly
restructured Maryland's electric utility industry and modified the industry's
tax structure.
In the Restructuring Order discussed below, the Maryland PSC addressed the
major provisions of the Act. The accompanying tax legislation is discussed in
detail in Note 4 of our 2000 Annual Report on Form 10-K.
On November 10, 1999, the Maryland PSC issued a Restructuring Order that
resolved the major issues surrounding electric restructuring, accelerated the
timetable for customer choice, and addressed the major provisions of the Act.
The Restructuring Order also resolved the electric restructuring proceeding
(transition costs, customer price protections, and unbundled rates for electric
services) and a petition filed in September 1998 by the Office of People's
Counsel (OPC) to lower our electric base rates. The major provisions of the
Restructuring Order are discussed in Note 4 of our 2000 Annual Report on Form
10-K.
As a result of the deregulation of electric generation, the following
occurred effective July 1, 2000:
o All customers can choose their electric energy supplier. BGE will provide
a standard offer service for customers that do not select an alternative
supplier. In either case, BGE will continue to deliver electricity to all
customers in areas traditionally served by BGE.
o BGE reduced residential base rates by approximately 6.5%, on average,
about $54 million a year. These rates will not change before July 2006.
o BGE transferred, at book value, its nuclear generating assets, its
nuclear decommissioning trust fund, and related liabilities to Calvert
Cliffs Nuclear Power Plant, Inc. In addition, BGE transferred, at book
value, its fossil generating assets and related liabilities and its
partial ownership interest in two coal plants and a hydroelectric plant
located in Pennsylvania to Constellation Power Source Generation.
total, these generating assets represent about 6,240 megawatts of
generation capacity with a total net book value at June 30, 2000 of
approximately $2.4 billion.
o BGE assigned approximately $47 million to Calvert Cliffs Nuclear Power
Plant, Inc. and $231 million to Constellation Power Source Generation of
tax-exempt debt related to the transferred assets. Also, Constellation
Power Source Generation issued approximately $366 million in unsecured
promissory notes to BGE. All of these notes have been repaid by
Constellation Power Source Generation. The proceeds were used to service
the current maturities of certain BGE long-term debt.
o BGE transferred equity associated with the generating assets to Calvert
Cliffs Nuclear Power Plant, Inc. and Constellation Power Source
Generation.
o The fossil fuel and nuclear fuel inventories, materials and supplies, and
certain purchased power contracts of BGE were also assumed by these
subsidiaries.
20
Effective July 1, 2000, BGE provides standard offer service to customers at
fixed rates over various time periods during the transition period for those
customers that do not choose an alternate supplier. In addition, the electric
fuel rate was discontinued effective July 1, 2000. Constellation Power Source
provides BGE with the energy and capacity required to meet its standard offer
service obligations for the first three years of the transition period. The
energy and capacity for the remaining years in the transition period were
competitively bid and BGE has received several bids including one for
Constellation Power Source. BGE currently is evaluating these bids and expects
to award contracts by the end of August 2001. We expect the Maryland PSC to
review the results of the competitive bid process.
Constellation Power Source obtains the energy and capacity to supply BGE's
standard offer service obligations from affiliates that own Calvert Cliffs
Nuclear Power Plant (Calvert Cliffs) and BGE's former fossil plants,
supplemented with energy and capacity purchased from the wholesale market as
necessary.
Other States
- ------------
Our domestic merchant energy business is focused on expanding its business
through marketing energy products, including structured transactions, to
wholesale customers and acquiring control of additional generating facilities
when necessary to support our marketing operation. This business will focus on
states with strong growth in energy demand and that provide opportunities
through ongoing deregulation and the creation of competitive markets. Delays in,
or the ultimate form of, deregulation of electric generation in various states
may affect our domestic merchant energy business strategy.
Our domestic merchant energy business has $304.0 million invested in power
projects that sell 142 megawatts of electricity in California under power
purchase agreements as discussed in the California Power Purchase Agreements
section in the Notes to Consolidated Financial Statements on page 15. The
counterparties to the agreements are two California investor-owned utilities,
Southern California Edison Company (SCE) and Pacific Gas and Electric Company
(PGE). Due to various factors, including shortage of generation and the high
cost of natural gas, these utilities' financial condition has been severely
impacted because they are paying more for power than they are allowed to recover
from their customers under the deregulation plan in California. As a result,
these utilities did not maintain current payments for the power they purchased
to meet their customers' energy needs and the credit ratings of these utilities
were downgraded below investment grade. Unable to meet its obligation to power
suppliers, the California Power Exchange ceased operations in January 2001 and
filed for bankruptcy in March 2001. California's Department of Water Resources
has since assumed the role of electricity procurement in California and is
considering raising money through the sale of bonds to pay back creditors of the
California Power Exchange and the California Independent System Operator.
Further, on April 6, 2001, PGE filed for protection under Chapter 11 of the
United States Bankruptcy Code.
Due to the deteriorating financial condition of these utilities, our
California projects did not receive full payment for electricity delivered to
these utilities for the period November 1, 2000 through April 6, 2001. Our
projects that sell power to SCE began receiving current payments for power
delivered beginning April 1, 2001, and our projects that sell power to PGE began
receiving current payments for power delivered beginning April 7, 2001. Our
portion of the amount due from these utilities for the period November 1, 2000
through April 6, 2001 was approximately $50 million. While we expect to be paid
the amount owed to us, we cannot predict when payment will occur or if full
payment will be received. We have taken reserves in amounts we believe to be
reasonable under the current circumstances.
However, if the ultimate resolution of the events in California prevents
collection of unpaid balances under power purchase agreements by some or all of
our projects, in an amount in excess of the reserves that we have taken, it
could have a material impact on our financial results. Additionally, if the
events in California result in a modification or termination of these agreements
that reduces future cash flows, we would have to evaluate whether our
investments in the power projects that are parties to the agreements are
impaired. An impairment of these investments could have a material impact on our
financial results. Our domestic merchant energy business does not have any other
direct agreements with these utilities. However, we may be impacted if one or
more of our other counterparties are significantly affected by the events in
California, or by the operation of the California Department of Water Resources
and the California Independent System Operator.
Gas Competition
- ---------------
Currently, no regulation exists for the wholesale price of natural gas as a
commodity, and the regulation of interstate transmission at the federal level
has been reduced. All BGE gas customers have the option to purchase gas from
other suppliers.
21
Regulation by the Maryland PSC
- ------------------------------
In addition to electric restructuring which was discussed earlier, regulation
by the Maryland PSC influences BGE's businesses.
Under traditional rate regulation that continues after July 1, 2000 for
BGE's electric transmission and distribution, and gas businesses, the
Maryland PSC determines the rates we can charge our customers. Prior to
July 1, 2000, BGE's regulated electric rates consisted primarily of a "base
rate" and a "fuel rate." Effective July 1, 2000, BGE discontinued its
electric fuel rate and unbundled its rates to show separate components for
delivery service, competitive transition charges, standard offer services
(generation), transmission, universal service, and taxes. The rates for BGE's
regulated gas business continue to consist of a "base rate" and a "fuel rate."
Base Rate
- ---------
The base rate is the rate the Maryland PSC allows BGE to charge its customers
for the cost of providing them service, plus a profit. BGE has both an electric
base rate and a gas base rate. Higher electric base rates apply during the
summer when the demand for electricity is higher. Gas base rates are not
affected by seasonal changes.
BGE may ask the Maryland PSC to increase base rates from time to time. The
Maryland PSC historically has allowed BGE to increase base rates to recover
increased utility plant asset costs, plus a profit, beginning at the time of
replacement. Generally, rate increases improve our utility earnings because they
allow us to collect more revenue. However, rate increases are normally granted
based on historical data and those increases may not always keep pace with
increasing costs. Other parties may petition the Maryland PSC to decrease base
rates.
On November 17, 1999, BGE filed an application with the Maryland PSC to
increase its gas base rates. The Maryland PSC authorized a $6.4 million annual
increase in our gas base rates effective June 22, 2000.
As a result of the Restructuring Order, BGE's residential electric base
rates are frozen until 2006. Electric delivery service rates are frozen for a
four-year period for commercial and industrial customers. The generation and
transmission components of rates are frozen for different time periods depending
on the service options selected by those customers.
Fuel Rate
- ---------
Through June 30, 2000, we charged our electric customers separately for the fuel
we used to generate electricity (nuclear fuel, coal, gas, or oil) and for the
net cost of purchases and sales of electricity. We charged the actual cost of
these items to the customer with no profit to us. If these fuel costs went up,
the Maryland PSC permitted us to increase the fuel rate.
Under the Restructuring Order, BGE's electric fuel rate was frozen until
July 1, 2000, at which time the fuel rate clause was discontinued. We deferred
the difference between our actual costs of fuel and energy and what we collected
from customers under the fuel rate through June 30, 2000.
In September 2000, the Maryland PSC approved the collection of the $54.6
million accumulated difference between our actual costs of fuel and energy and
the amounts collected from customers that were deferred under the electric fuel
rate clause through June 30, 2000. We are collecting this accumulated difference
from customers over the twelve-month period beginning October 2000. Effective
July 1, 2000, earnings are affected by the changes in the cost of fuel and
energy.
We charge our gas customers separately for the natural gas they purchase
from us. The price we charge for the natural gas is based on a market based
rates incentive mechanism approved by the Maryland PSC. We discuss market based
rates in more detail in the Gas Cost Adjustments section on page 29 and in Note
1 of our 2000 Annual Report on Form 10-K.
FERC Regulation--Regional Transmission Organizations
- ----------------------------------------------------
In December 1999, FERC issued Order 2000, amending its regulations under the
Federal Power Act to advance the formation of Regional Transmission
Organizations (RTOs). The regulations require that each public utility that
owns, operates, or controls facilities for the transmission of electric energy
in interstate commerce make certain filings with respect to forming and
participating in a RTO. FERC also identified the minimum characteristics and
functions that a transmission entity must satisfy in order to be considered a
RTO.
According to Order 2000, a public utility that is a member of an existing
transmission entity that has been approved by FERC as in conformance with the
Independent System Operator (ISO) principles set forth in the FERC Order No.
888, such as BGE, through its membership in PJM (Pennsylvania-New
Jersey-Maryland) Interconnection, was required to make a filing no later than
January 15, 2001. PJM and the joint transmission owners, including BGE, made the
filing on October 11, 2000. That filing explained the extent to which PJM met
the minimum characteristics and functions of a RTO and explained its plans to
conform to these characteristics and functions.
On July 12, 2001, FERC provisionally granted PJM RTO status and ordered it
to engage in mediation with the New York ISO and the New England ISO in regard
to creating a business plan to form one Northeast RTO, using PJM as a platform.
This mediation proceeding is currently ongoing.
22
As a member of PJM, an existing ISO, BGE does not expect to be materially
impacted by Order 2000 or the July 12, 2001 order. However, we are appealing two
requirements of Order 2000 whereby:
o we would be required to go through PJM to make a filing with FERC to
change our transmission rates, and
o we would be required to transfer operational control of our transmission
facilities to PJM.
The U.S. Supreme Court agreed to hear an appeal by others of FERC Order 888. We
cannot predict the outcome of this appeal or the impact on BGE at this time.
Weather
- -------
Domestic Merchant Energy Business
- ---------------------------------
Weather conditions in the different regions of North America influence the
financial results of our domestic merchant energy business. Typically, demand
for electricity and its price are higher in the summer and the winter, when
weather is more extreme. However, all regions of North America typically do not
experience extreme weather conditions at the same time. Since the majority of
our generating plants currently are located in PJM, our financial results are
affected by weather conditions in this area.
Current weather conditions also can affect the forward market price of
energy commodity and derivative contracts used by our power marketing operation
that are accounted for on a mark-to-market basis. To the extent that our power
marketing operation purchases and sells such contracts, our financial results
could be influenced by the impact that weather conditions have on the market
price of such contracts.
BGE
- ---
Weather affects the demand for electricity and gas for our regulated businesses.
Very hot summers and very cold winters increase demand. Mild weather reduces
demand. Residential sales for our regulated businesses are impacted more by
weather than commercial and industrial sales, which are mostly affected by
business needs for electricity and gas.
However, the Maryland PSC allows us to record a monthly adjustment to our
regulated gas business revenues to eliminate the effect of abnormal weather
patterns. We discuss this further in the Weather Normalization section on page
29.
We measure the weather's effect using "degree days." A degree day is the
difference between the average daily actual temperature and a baseline
temperature of 65 degrees. Cooling degree days result when the average daily
actual temperature exceeds the 65 degree baseline. Heating degree days result
when the average daily actual temperature is less than the baseline.
During the cooling season, hotter weather is measured by more cooling degree
days and results in greater demand for electricity to operate cooling systems.
During the heating season, colder weather is measured by more heating degree
days and results in greater demand for electricity and gas to operate heating
systems.
We show the number of heating degree days in the quarters and six months ended
June 30, 2001 and 2000, and the percentage change in the number of degree days
between these periods in the following table:
Quarter Six Months
Ended Ended
June 30 June 30
2001 2000 2001 2000
- --------------------------------------------------
Heating degree days 471 512 2,918 2,817
Percent change
from prior period (8.0)% 3.6%
Cooling degree days 262 263 262 268
Percent change
from prior period (0.4)% (2.2)%
Other Factors
- -------------
Other factors, aside from weather, impact the demand for electricity and gas in
our regulated businesses. These factors include the "number of customers" and
"usage per customer" during a given period. We use these terms later in our
discussions of regulated electric and gas operations. In those sections, we
discuss how these and other factors affected electric and gas sales during the
periods presented.
The number of customers in a given period is affected by new home and
apartment construction and by the number of businesses in our service territory.
Under the Restructuring Order, BGE's electric customers can become delivery
service customers only and can purchase their electricity from other sources. We
will collect a delivery service charge to recover the fixed costs for the
service we provide. The remaining electric customers will receive standard offer
service from BGE at the fixed rates provided by the Restructuring Order. Usage
per customer refers to all other items impacting customer sales that cannot be
measured separately. These factors include the strength of the economy in our
service territory. When the economy is healthy and expanding, customers tend to
consume more electricity and gas. Conversely, during an economic downtrend, our
customers tend to consume less electricity and gas.
23
Results of Operations for the Quarter and Six Months Ended June 30, 2001
- ------------------------------------------------------------------------
Compared with the Same Periods of 2000
- --------------------------------------
In this section, we discuss our earnings and the factors affecting them. We
begin with a general overview, then separately discuss earnings for our
operating segments. Changes in fixed charges, income taxes, and other income are
discussed in the aggregate for all segments in the Consolidated Nonoperating
Income and Expenses section on page 31.
Overview
- --------
Total Earnings Per Share of Common Stock
Quarter Ended Six Months Ended
June 30, June 30,
2001* 2000 2001* 2000
- -----------------------------------------------------------
Earnings before
nonrecurring charges
included in operations:
Domestic merchant energy $.32 $.11 $ .60 $.24
Regulated electric .11 .32 .29 .55
Regulated gas .02 .02 .20 .15
Other nonregulated .01 (.08) .04 (.06)
- -----------------------------------------------------------
Total earnings per
share before
nonrecurring charges
included in
operations: .46 .37 1.13 .88
Nonrecurring charges
included in operations:
Deregulation
transition cost -- (.10) -- (.10)
TVSERP -- (.01) -- (.03)
- -----------------------------------------------------------
Earnings per share
before
cumulative effect of
change in accounting
principle .46 .26 1.13 .75
Cumulative effect of
change in accounting
principle, net of
income taxes -- -- .06 --
- -----------------------------------------------------------
Total earnings per share $.46 $.26 $1.19 $.75
===========================================================
*Earnings for the periods presented reflect a significant shift from the
regulated electric business to the domestic merchant energy business as a result
of the transfer of BGE's electric generation assets to nonregulated subsidiaries
on July 1, 2000 in accordance with the Restructuring Order. We discuss the
Restructuring Order in more detail in Current Issues - Electric Competition
section on page 20.
Quarter Ended June 30, 2001
- ---------------------------
Our total earnings for the quarter ended June 30, 2001 increased $36.0 million,
or $.20 per share, compared to the same period of 2000. Our total earnings
increased mostly because of the following:
o We recorded $37.5 million pre-tax, or approximately $.15 per share, of
amortization expense for the reduction of our generating plants
associated with the Restructuring Order in the second quarter of 2000
that had a negative impact in that quarter.
o We recorded a nonrecurring expense of $15.0 million, after-tax, for
deregulation transition cost to a third party incurred by our power
marketing business to provide BGE's standard offer service requirements
in the second quarter of 2000 that had a negative impact in that
quarter.
o We recorded a nonrecurring expense of $1.7 million, after-tax, for BGE
employees that elected to participate in a Targeted Voluntary Special
Early Retirement Program (TVSERP) in the second quarter of 2000 that had
a negative impact in that quarter.
These were partially offset by $11.6 million pre-tax, or $.04 per share,
recorded in the second quarter 2001 related to the impact of a 6.5% annual
residential rate reduction that was effective July 1, 2000.
Six Months Ended June 30, 2001
- ------------------------------
Our total earnings for the six months ended June 30, 2001 increased $75.7
million, or $.44 per share, compared to the same period of 2000. Our total
earnings increased mostly because of the following:
o We recorded $75.0 million pre-tax, or approximately $.30 per share, of
amortization expense for the reduction of our generating plants
associated with the Restructuring Order in 2000 that had a negative
impact in that period.
o We recorded a nonrecurring expense of $15.0 million, after-tax, for
deregulation transition cost to a third party incurred by our power
marketing business that had a negative impact in 2000 as discussed
above.
o We recorded a nonrecurring expense of $4.2 million, after-tax, for BGE
employees that elected to participate in the TVSERP in 2000 that had a
negative impact in that period.
o We recorded an $8.5 million after-tax, or $.06 per share, gain for the
cumulative effect of adopting Statement of Financial Accounting Standard
(SFAS) No. 133, Accounting for Derivative Instruments and Hedging
Activities, as amended, in the first quarter of 2001.
These were partially offset by $17.6 million pre-tax, or $.07 per share,
recorded in 2001 related to the impact of a 6.5% annual residential rate
reduction that was effective July 1, 2000.
Earnings per share contributions from all our business segments were
impacted by additional dilution resulting from the issuance of 13.2 million
shares of common stock between January 1, 2001 and the date of our report.
In the following sections, we discuss our earnings by business segment in
greater detail.
24
Domestic Merchant Energy Business
- ---------------------------------
Our domestic merchant energy business engages primarily in power marketing and
domestic power generation. We describe this business in more detail in our 2000
Annual Report on Form 10-K in Item 1. Business -- Domestic Merchant Energy
Business.
As discussed in the Current Issues -- Electric Competition section on page 20,
our domestic merchant energy business was significantly impacted by the
July 1, 2000 implementation of customer choice in Maryland. At that time, BGE's
generating assets became part of our nonregulated domestic merchant energy
business, and Constellation Power Source began selling to BGE the energy and
capacity required to meet its standard offer service obligations for the first
three years of the transition period.
Constellation Power Source obtains the energy and capacity to supply BGE's
standard offer service obligations from affiliates that own Calvert Cliffs and
BGE's former fossil plants, supplemented with energy and capacity purchased from
the wholesale energy market as necessary. Constellation Power Source also
manages our wholesale market price risk.
In addition, effective July 1, 2000, domestic merchant energy business
revenues include 90% of the competitive transition charges BGE collects from its
customers (CTC revenues) and the portion of BGE's revenues providing for nuclear
decommissioning costs.
Our earnings are exposed to various risks of the competitive marketplace,
including imbalances in supply and demand and changes in future commodity
prices, that may impact the financial results of our domestic merchant energy
business. For example, our earnings are exposed to the risks of the competitive
wholesale electricity market to the extent that our domestic merchant energy
business has to purchase energy and/or capacity to meet obligations to supply
power or meet other energy-related contractual arrangements at prices which may
approach or exceed the applicable fixed sales price obligations. If the price of
obtaining energy in the wholesale market exceeds the fixed sales price, our
earnings would be adversely affected.
We are also affected by operational risk, that is, the risk that a
generating plant will not be available to produce energy when the energy is
required. Imbalances in demand and supply can occur not only because of plant
outages, but also because of transmission constraints, or extreme temperatures
(hot or cold) causing demand to exceed available supply.
We discuss our market risk further in our 2000 Annual Report on Form 10-K in
Item 7. Management Discussion and Analysis -- Market Risk. We cannot estimate
the impact of the increased financial risks associated with the competitive
wholesale electricity market. However, these financial risks could have a
material impact on our financial results.
Earnings
- --------
Quarter Ended Six Months Ended
June 30, June 30,
2001 2000 2001 2000
- -----------------------------------------------------------
(In millions, except per share amounts)
Revenues $372.5 $64.1 $709.2 $133.4
Operating expenses 243.6 54.3 461.8 90.6
Depreciation and
amortization 39.9 1.8 79.5 3.3
Taxes other than income
taxes 11.2 -- 22.4 --
- -----------------------------------------------------------
Income from operations $ 77.8 $ 8.0 $145.5 $ 39.5
===========================================================
Net income $ 52.4 $ 1.9 $ 94.8 $ 20.1
===========================================================
Total earnings per share
before nonrecurring
charges included in
operations: $.32 $.11 $.60 $.24
Deregulation
transition cost -- (.10) -- (.10)
- -----------------------------------------------------------
Earnings per share $.32 $.01 $.60 $.14
===========================================================
Above amounts include intercompany transactions eliminated in our Consolidated
Financial Statements. The Information by Operating Segment section within the
Notes to Consolidated Financial Statements on page 12 provides a reconciliation
of operating results by segment to our Consolidated Financial Statements.
Revenues
- --------
During the quarter ended June 30, 2001, domestic merchant energy revenues
increased $308.4 million compared to the same period of 2000 mostly because of:
o a $281.2 million increase related to providing BGE the energy and
capacity required to meet its standard offer service obligation effective
July 1, 2000, and
o a $43.4 million increase related to CTC and decommissioning revenues
included in the domestic merchant energy business effective July 1, 2000.
These increases were partially offset by lower revenues from our domestic
generation operation.
During the six months ended June 30, 2001, domestic merchant energy revenues
increased $575.8 million compared to the same period of 2000 mostly because of:
o a $532.5 million increase related to providing BGE the energy and
capacity required to meet its standard offer service obligation effective
July 1, 2000,
o a $94.1 million increase related to CTC and decommissioning revenues
included in the domestic merchant energy business effective July 1, 2000.
These increases were partially offset by lower revenues from our power
marketing and domestic generation operations.
We discuss the revenues for our power marketing and domestic generation
operations in the following sections.
25
Power Marketing
- ---------------
During the quarter ended June 30, 2001, power marketing revenues increased
slightly compared to the same period of 2000 mostly because of higher revenues
from new structured transactions partially offset by the effect of unfavorable
market price changes on open trading positions.
During the six months ended June 30, 2001, power marketing revenues
decreased compared to the same period of 2000 mostly because of the effect of
unfavorable market price changes on open trading positions partially offset by
higher revenues from new structured transactions.
Constellation Power Source uses the mark-to-market method of accounting for
its energy trading activities. We discuss the mark-to-market method of
accounting and Constellation Power Source's activities in more detail in Note 1
of our 2000 Annual Report on Form 10-K. As a result of the nature of its
operations and the use of mark-to-market accounting, Constellation Power
Source's revenues and earnings will fluctuate. We cannot predict these
fluctuations, but the effect on our revenues and earnings could be material. The
primary factors that cause these fluctuations are:
o the number and size of new transactions,
o the magnitude and volatility of changes in commodity prices and interest
rates, and
o the number and size of open commodity and derivative positions
Constellation Power Source holds or sells.
Constellation Power Source's management uses its best estimates to determine
the fair value of commodity and derivative positions it holds and sells. These
estimates consider various factors including closing exchange and
over-the-counter price quotations, time value, volatility factors, and credit
exposure. However, it is possible that future market prices could vary from
those used in recording assets and liabilities from power marketing and trading
activities, and such variations could be material.
Domestic Generation
- -------------------
During the quarter ended June 30, 2001, domestic generation revenues decreased
compared to the same period of 2000 mostly because in April 2000, Constellation
Operating Services Inc. (COSI), a subsidiary of Constellation Power, Inc.,
recognized a $13.3 million gain on the termination of an operating arrangement
and sale of certain subsidiaries to Orion Power Holdings Inc.
During the six months ended June 30, 2001, domestic generation revenues
decreased compared to the same period of 2000 mostly because of the 2000 gain
discussed above partially offset by a $9.5 million gain on the sale of a project
under development located in the PJM region recorded in March 2001.
California Power Purchase Agreements
- ------------------------------------
Our domestic generation operation has $304.0 million invested in 14 projects
that sell electricity in California to SCE and PGE under power purchase
agreements called "Interim Standard Offer No. 4" agreements.
Under these agreements, the electricity rates changed from fixed rates to
variable rates beginning in 1996. In 2000, the last four projects transitioned
to variable rates. During the quarter and six months ended June 30, 2001,
revenues from these projects were about the same compared to the same periods of
2000. While energy rates were higher for the six months period compared to the
same period of 2000, this was offset by reserves established for our exposure in
California. We discuss the developments in California in the Current
Issues--Electric Competition section on page 21.
We also describe these projects and the transition process in the Notes to
Consolidated Financial Statements and Note 10 of our 2000 Annual Report on Form
10-K.
Operating Expenses
- ------------------
Domestic merchant energy operating expenses increased $189.3 million for the
quarter and $371.2 million for the six months ended June 30, 2001 compared to
the same periods of 2000 mostly because of:
o increases in fuel costs of $103.0 million for the quarter and
$206.4 million for the six months period, and
o increases in operations and maintenance costs of $102.7 million for the
quarter and $194.7 million for the six months period.
These costs were associated with the generation plants that were transferred
from BGE effective July 1, 2000. This was partially offset by lower operating
expenses by our power marketing operation mostly because in the second quarter
of 2000, this operation recognized $24.0 million for deregulation transition
cost to a third party that had a negative impact in that period. The power
marketing operation also had lower transaction related expenses.
Depreciation and Amortization Expense
- -------------------------------------
Domestic merchant energy depreciation and amortization expense increased $38.1
million for the quarter and $76.2 million for the six months ended June 30, 2001
compared to the same periods of 2000 mostly because of expenses associated with
the generation plants that were transferred from BGE effective July 1, 2000.
Taxes Other than Income Taxes
- -----------------------------
Domestic merchant energy taxes other than income taxes increased $11.2 million
for the quarter and $22.4 million for the six months ended June 30, 2001
compared to the same periods of 2000 mostly because of taxes other than income
taxes associated with the generation plants that were transferred from BGE
effective July 1, 2000.
26
Regulated Electric Business
- ---------------------------
As previously discussed, our regulated electric business was significantly
impacted by the July 1, 2000 implementation of customer choice. These changes
include BGE's generating assets and related liabilities becoming part of our
nonregulated domestic merchant energy business on that date.
Earnings
- --------
Quarter Ended Six Months Ended
June 30, June 30,
2001 2000 2001 2000
- --------------------------------------------------------
(In millions, except per share amounts)
Electric revenues $497.5 $565.4 $989.8 $1,090.0
Electric fuel and
purchased energy 293.9 124.7 559.7 244.1
Operations and
maintenance 62.9 168.6 124.7 322.7
Depreciation and
amortization 43.3 112.2 86.7 224.8
Taxes other than
income taxes 35.0 44.3 70.9 90.4
- --------------------------------------------------------
Income from
operations $ 62.4 $115.6 $147.8 $ 208.0
========================================================
Net income $ 18.0 $ 47.3 45.7 $ 78.1
========================================================
Total earnings per
share before
nonrecurring
charges included
in operations: $.11 $.32 $.29 $.55
TVSERP -- (.01) -- (.03)
- --------------------------------------------------------
Earnings per share $.11 $.31 $.29 $.52
========================================================
Above amounts include intercompany transactions eliminated in our Consolidated
Financial Statements. The Information by Operating Segment section within the
Notes to Consolidated Financial Statements on page 12 provides a reconciliation
of operating results by segment to our Consolidated Financial Statements.
Electric Revenues
- -----------------
The changes in electric revenues in 2001 compared to 2000 were caused by:
Quarter Six Months
Ended Ended
June 30, June 30,
2001 vs. 2000 2001 vs. 2000
- ---------------------------------------------------
(In millions)
Electric system
sales volumes $(0.1) $ 8.9
Rates (48.4) (84.3)
Fuel rate surcharge 12.5 27.3
- ---------------------------------------------------
Total change in
electric revenues
from electric
system sales (36.0) (48.1)
Interchange and
other sales (30.9) (53.8)
Other (1.0) 1.7
- ---------------------------------------------------
Total change in
electric revenues $(67.9) $(100.2)
===================================================
Electric System Sales Volumes
- -----------------------------
"Electric system sales volumes" are sales to customers in our service territory
at rates set by the Maryland PSC. These sales do not include interchange sales
and sales to others.
The percentage changes in our electric system sales volumes, by type of
customer, in 2001 compared to 2000 were:
Quarter Ended Six Months Ended
June 30, June 30,
2001 vs. 2000 2001 vs. 2000
- -----------------------------------------------------
Residential (0.6)% 3.2%
Commercial 0.2 1.5
Industrial 1.0 0.3
During the quarter ended June 30, 2001, we sold about the same amount of
electricity to all customers compared to the same period of 2000.
During the six months ended June 30, 2001, we sold more electricity to
residential customers compared to the same period of 2000 due to higher usage
per customer and an increased number of customers. We sold more electricity to
commercial customers mostly due to an increased number of customers. We sold
about the same amount of electricity to industrial customers.
Rates
- -----
Prior to July 1, 2000, our rates primarily consisted of an electric base rate
and an electric fuel rate. Effective July 1, 2000, BGE discontinued its electric
fuel rate and unbundled its rates to show separate components for delivery
service, transition charges, standard offer services (generation), transmission,
universal service, and taxes. BGE's rates also were frozen in total except for
the implementation of a residential base rate reduction totaling approximately
$54 million annually. In addition, 90% of the CTC revenues BGE collects and the
portion of its revenues providing for decommissioning costs, are included in
revenues of the domestic merchant energy business effective July 1, 2000.
Rate revenues decreased compared to the same periods of 2000 mostly due to
the decreases caused by:
o the 6.5% annual residential rate reduction of $11.6 million for the
quarter and $17.6 million for the six months period, and
o the $43.4 million for the quarter and $94.1 million for the six months
period related to the transfer of revenues to the domestic merchant
energy business discussed above.
These decreases were partially offset by the other net impacts of the rate
restructuring discussed above.
Fuel Rate Surcharge
- -------------------
In September 2000, the Maryland PSC approved the collection of the $54.6 million
accumulated difference between our actual costs of fuel and energy and the
amounts collected from customers that were deferred under the electric fuel rate
clause through June 30, 2000. We discuss this further in the Electric Fuel Rate
Clause section on page 28.
27
Interchange and Other Sales
- ---------------------------
"Interchange and other sales" are sales in the PJM energy market and to others.
PJM is an ISO that also operates a regional power pool with members that include
many wholesale market participants, as well as BGE, and other utility companies.
Prior to the implementation of customer choice, BGE sold energy to PJM members
and to others after it had satisfied the demand for electricity in its own
system.
Effective July 1, 2000, BGE no longer engages in interchange sales and these
activities are included in our domestic merchant energy business which resulted
in a decrease in interchange and other sales for the quarter and six months
ended June 30, 2001 compared to the same periods of 2000.
Electric Fuel and Purchased Energy Expenses
- -------------------------------------------
Quarter Ended Six Months Ended
June 30, June 30,
2001 2000 2001 2000
- ---------------------------------------------------------
(In millions)
Actual costs $281.6 $131.2 $532.9 $253.8
Net recovery
(deferral) of
costs under
electric fuel
rate clause 12.3 (6.5) 26.8 (9.7)
- ---------------------------------------------------------
Total electric
fuel and
purchased
energy expenses $293.9 $124.7 $559.7 $244.1
=========================================================
Actual Costs
- ------------
Our actual costs of fuel and purchased energy were higher compared to the same
period of 2000 mostly because of the deregulation of electric generation. As
discussed in the Current Issues--Electric Competition section on page 20,
effective July 1, 2000, BGE transferred its generating assets to, and began
purchasing substantially all of the energy and capacity required to provide
electricity to standard offer service customers from, the domestic merchant
energy business.
The cost of energy BGE purchased from our domestic merchant energy business
was $281.2 million for the quarter and $532.5 million for the six months ended
June 30, 2001. The higher amount paid for purchased energy is offset by the
absence of $103.0 million for the quarter and $206.4 million for the six months
in fuel costs, and lower operations and maintenance, depreciation, taxes, and
other costs at BGE as a result of no longer owning and operating the transferred
electric generation plants.
Prior to July 1, 2000, BGE's purchased fuel and energy costs only included
actual costs of fuel to generate electricity (nuclear fuel, coal, gas, or oil)
and electricity we bought from others.
Electric Fuel Rate Clause
- -------------------------
Prior to July 1, 2000, we deferred (included as an asset or liability on the
Consolidated Balance Sheets and excluded from the Consolidated Statements of
Income) the difference between our actual costs of fuel and energy and what we
collected from customers under the fuel rate in a given period. Effective July
1, 2000, the fuel rate clause was discontinued under the terms of the
Restructuring Order. In September 2000, the Maryland PSC approved the collection
of the $54.6 million accumulated difference between our actual costs of fuel and
energy and the amounts collected from customers that were deferred under the
electric fuel rate clause through June 30, 2000. We are collecting this
accumulated difference from customers over the twelve-month period beginning
October 2000.
Electric Operations and Maintenance Expenses
- --------------------------------------------
Regulated electric operations and maintenance expenses decreased $105.7 million
for the quarter and $198.0 million for the six months ended June 30, 2001
compared to the same periods of 2000 mostly because of the following:
o Effective July 1, 2000, costs of $102.7 million for the quarter and
$194.7 million for the six months period were no longer incurred by this
business segment. These costs were associated with the electric
generation assets that were transferred to the domestic merchant energy
business.
o In addition, BGE recognized expenses of $2.8 million for the quarter and
$7.0 million for the six months periods for employees that elected to
participate in a Targeted Voluntary Special Early Retirement Program in
2000 that had a negative impact in those periods.
Electric Depreciation and Amortization Expense
- ----------------------------------------------
Regulated electric depreciation and amortization expense decreased $68.9 million
for the quarter and $138.1 million for the six months ended June 30, 2001
compared to the same periods of 2000 mostly because of:
o the absence of $37.5 million for the quarter and $75.0 million for the
six months period of amortization expense recorded in 2000 associated
with the $150 million reduction of our generating plants provided for in
the Restructuring Order, and
o $37.6 million for the quarter and 75.1 million for the six months period
of expenses associated with the transfer of the generation assets to the
domestic merchant energy business effective July 1, 2000.
These decreases were offset partially by more electric plant in service (as
our level of plant in service changes, the amount of depreciation and
amortization expense changes) and higher amortization associated with regulatory
assets.
Electric Taxes Other Than Income Taxes
- --------------------------------------
Regulated electric taxes other than income taxes decreased $9.3 million for the
quarter and $19.5 million for the six months ended compared to the same periods
of 2000. This was mostly due to the absence of taxes other than income taxes
associated with the generation assets that were transferred to the domestic
merchant energy business effective July 1, 2000.
28
Regulated Gas Business
- ----------------------
Earnings
- --------
Quarter Ended Six Months Ended
June 30, June 30,
2001 2000 2001 2000
- --------------------------------------------------------
(In millions, except per share amounts)
Gas revenues $109.7 $92.7 $467.3 $287.8
Gas purchased for
resale 52.2 40.9 305.1 143.8
Operations and
maintenance 24.6 23.3 49.2 46.9
Depreciation and
amortization 12.2 11.1 26.5 24.2
Taxes other than
income taxes 8.3 6.1 18.4 20.0
- --------------------------------------------------------
Income from operations $ 12.4 $11.3 $ 68.1 $ 52.9
========================================================
Net income $ 3.0 $ 2.3 $ 31.7 $ 22.6
========================================================
Earnings per share $.02 $.02 $.20 $.15
========================================================
Above amounts include intercompany transactions eliminated in our Consolidated
Financial Statements. The Information by Operating Segment section within the
Notes to Consolidated Financial Statements on page 12 provides a reconciliation
of operating results by segment to our Consolidated Financial Statements.
Earnings from the regulated gas business increased during the six months
ended June 30, 2001 compared to 2000 mostly due to the sharing mechanism under
our gas cost adjustment clauses and the increase in our base rates.
All BGE customers have the option to purchase gas from other suppliers. To
date, customer choice has not had a material effect on our, and BGE's, financial
results.
Gas Revenues
- ------------
The changes in gas revenues in 2001 compared to 2000 were caused by:
Quarter Ended Six Months Ended
June 30, June 30,
2001 vs. 2000 2001 vs. 2000
- --------------------------------------------------------
(In millions)
Gas system sales
volumes $ 0.2 $ 16.7
Base rates 1.8 3.3
Weather normalization 1.5 (5.9)
Gas cost adjustments 11.2 116.2
- --------------------------------------------------------
Total change in
gas revenues
from gas
system sales 14.7 130.3
Off-system sales 1.4 47.6
Other 0.9 1.6
- --------------------------------------------------------
Total change in
gas revenues $17.0 $179.5
========================================================
Gas System Sales Volumes
- ------------------------
The percentage changes in our gas system sales volumes, by type of customer, in
2001 compared to 2000 were:
Quarter Ended Six Months Ended
June 30, June 30,
2001 vs. 2000 2001 vs. 2000
- ----------------------------------------------------
Residential (3.0)% 8.3%
Commercial 10.0 3.9
Industrial (30.1) (27.3)
During the quarter ended June 30, 2001, we sold less gas to residential
customers compared to the same period of 2000 mostly due to milder weather
partially offset by an increased number of customers. We sold more gas to
commercial customers mostly due to higher usage per customer. We sold less gas
to industrial customers mostly because of lower usage by Bethlehem Steel and
other industrial customers due to their switching to lower cost alternative fuel
sources.
During the six months ended June 30, 2001, we sold more gas to residential
customers compared to the same periods of 2000 mostly due to colder winter
weather, an increased number of customers, and higher usage per customer. We
sold more gas to commercial customers mostly due colder winter weather and
higher usage per customer. We sold less gas to industrial customers mostly
because of lower usage by Bethlehem Steel and other industrial customers due to
their switching to lower cost alternative fuel sources.
Base Rates
- ----------
During the quarter and six months ended June 30, 2001, base rate revenues
increased compared to the same periods of 2000 mostly because the Maryland PSC
authorized a $6.4 million annual increase in our base rates effective June 22,
2000.
Weather Normalization
- ---------------------
The Maryland PSC allows us to record a monthly adjustment to our gas revenues to
eliminate the effect of abnormal weather patterns on our gas system sales
volumes. This means our monthly gas revenues are based on weather that is
considered "normal" for the month and, therefore, are not affected by actual
weather conditions.
Gas Cost Adjustments
- --------------------
We charge our gas customers for the natural gas they purchase from us using gas
cost adjustment clauses set by the Maryland PSC as described in Note 1 of our
2000 Annual Report on Form 10-K. However, under market based rates, our actual
cost of gas is compared to a market index (a measure of the market price of gas
in a given period). The difference between our actual cost and the market index
is shared equally between shareholders and customers. During the quarter ended
June 30, 2001, the shareholders' portion was about the same compared to the same
period of 2000.
29
During the six months ended June 30, 2001, the shareholders' portion increased
$3.4 million compared to the same period of 2000.
Delivery service customers, including Bethlehem Steel, are not subject to the
gas cost adjustment clauses because we are not selling gas to them. We charge
these customers fees to recover the fixed costs for the transportation service
we provide. These fees are the same as the base rate charged for gas sales and
are included in gas system sales volumes.
During the quarter and six months ended June 30, 2001, gas cost adjustment
revenues increased compared to the same periods of 2000 mostly because we sold
more gas at a higher price to non-delivery service customers. In 2001, the
revenue increase reflects the significant increase in natural gas prices.
Off-System Sales
- ----------------
Off-system gas sales are low-margin direct sales of gas to wholesale suppliers
of natural gas outside our service territory. Off-system gas sales, which occur
after we have satisfied our customers' demand, are not subject to gas cost
adjustments. The Maryland PSC approved an arrangement for part of the margin
from off-system sales to benefit customers (through reduced costs) and the
remainder to be retained by BGE (which benefits shareholders). Changes in
off-system sales do not significantly impact earnings.
During the quarter ended June 30, 2001, revenues from off-system gas sales
increased compared to the same period of 2000 mostly because the gas we sold
off-system was at a higher price partially offset by less gas sold.
During the six months ended June 30, 2001, revenues from off-system gas
sales increased compared to the same period of 2000 mostly because we sold more
gas off-system at a higher price. In 2001, the revenue increase reflects the
significant increase in natural gas prices.
Gas Purchased For Resale Expenses
- ---------------------------------
Actual costs include the cost of gas purchased for resale to our customers and
for off-system sales. Actual costs do not include the cost of gas purchased by
delivery service customers.
During the quarter ended June 30, 2001, our gas costs increased compared to
the same period of 2000 mostly because we bought gas at a higher price. During
the six months ended June 30, 2001, our gas costs increased compared to the same
period of 2000 mostly because we bought more gas for both system and off-system
sales and all of the gas purchased was at a higher price.
Other Gas Operating Expenses
- ----------------------------
During the quarter and six months ended June 30, 2001, other gas operating
expenses were about the same compared to the same periods of 2000.
Other Nonregulated Businesses
- -----------------------------
Earnings
- --------
Quarter Ended Six Months Ended
June 30, June 30,
2001 2000 2001 2000
- ------------------------------------------------------------
(In millions, except per share amounts)
Revenues $145.0 $145.6 $361.7 $358.1
Operating expenses 120.6 141.5 305.1 328.3
Depreciation and
amortization 6.6 5.5 12.9 10.8
Taxes other than income
taxes 1.0 0.7 2.2 1.9
- ------------------------------------------------------------
Income from operations $ 16.8 $ (2.1) $ 41.5 $ 17.1
============================================================
Net income before
cumulative effect of
change in accounting
principle $ 2.2 $(11.9) $ 6.7 $ (9.1)
Cumulative effect of
change in accounting
principle -- -- 8.5 --
- ------------------------------------------------------------
Net income $ 2.2 $(11.9) $ 15.2 $ (9.1)
============================================================
Earnings per share before
cumulative effect of
change in accounting
principle $.01 $(.08) $.04 $(.06)
Cumulative effect of
change in accounting
principle -- -- .06 --
- ------------------------------------------------------------
Earnings per share $.01 $(.08) $.10 $(.06)
============================================================
Above amounts include intercompany transactions eliminated in our Consolidated
Financial Statements. The Information by Operating Segment section within the
Notes to Consolidated Financial Statements on page 12 provides a reconciliation
of operating results by segment to our Consolidated Financial Statements.
During the quarter ended June 30, 2001, earnings from our other
nonregulated businesses increased compared to the same period of 2000 mostly
because of a $9.0 million after-tax gain on the sale of one million shares of
the Orion investment and better market performance in our financial investments
business compared to the prior period, partially offset by a decline in the fair
value of the Orion warrant. Under SFAS No. 133, we are required to
mark-to-market the value of the Orion warrant through earnings each reporting
period. The value of the warrant may fluctuate under mark-to-market accounting
based on changes in the stock price of Orion and the volatility of that price in
future periods. We discuss the Orion warrant further in the Accounting Standard
Adopted section of the Notes to Consolidated Financial Statements on page 16.
During the six months ended June 30, 2001, earnings from our other
nonregulated businesses increased compared to the same period of 2000 mostly
because:
o We recorded a $9.0 million after-tax gain on the sale of one million
shares of the Orion investment as discussed above.
o We recorded an $ 8.5 million after-tax gain for the cumulative effect of
adopting SFAS No. 133 in the first quarter of 2001.
o Better market performance in our financial investments business.
30
Most of Constellation Real Estate Group's real estate and senior-living
projects are in the Baltimore-Washington corridor. The area has had a surplus of
available land in recent years and as a result these projects have been
economically hurt.
Constellation Real Estate's projects have continued to incur carrying costs
and depreciation over the years. Additionally, this operation has been charging
interest payments to expense rather than capitalizing them for some undeveloped
land where development activities have stopped. These carrying costs,
depreciation, and interest expenses have decreased earnings and are expected to
continue to do so.
Cash flow from real estate and senior-living operations has not been enough
to make the monthly loan payments on some of these projects. Cash shortfalls
have been covered by cash obtained from the cash flows of, or additional
borrowings by, other nonregulated subsidiaries.
We consider market demand, interest rates, the availability of financing,
competing demands for capital, and the strength of the economy in general when
making decisions about our real estate and senior-living projects. If we were to
decide to sell our projects, we could have write-downs. In addition, if we were
to sell our projects in the current market, we would have losses which could be
material, although the amount of the losses is hard to predict. Depending on
market conditions, we could also have material losses on any future sales.
Our current real estate and senior-living strategy is to hold each project
until we can realize a reasonable value for it. Under accounting rules, we are
required to write down the value of a project to market value in either of two
cases. The first is if we change our intent about a project from an intent to
hold to an intent to sell and the market value of that project is below book
value. The second is if the expected cash flow from the project is less than the
investment in the project.
Consolidated Nonoperating Income and Expenses
- ---------------------------------------------
Fixed Charges
- -------------
During the quarter and six months ended June 30, 2001, total fixed charges
decreased compared to the same periods of 2000 mostly because of lower interest
rates, offset partially by a higher level of debt outstanding.
Income Taxes
- ------------
During the quarter and six months ended June 30, 2001, our total income taxes
increased compared to the same periods of 2000 mostly because we had higher
taxable income from our domestic merchant energy and other nonregulated
businesses partially offset by lower taxable income from the utility business.
- --------------------------------------------------------------------------------
Financial Condition
- -------------------
Cash Flows
- ----------
Six Months
Ended
June 30,
2001 2000
- -----------------------------------------------------
(In millions)
Cash provided by (used in):
Operating Activities $ 261.0 $342.3
Investing Activities (568.5) (458.1)
Financing Activities 236.6 169.5
During the six months ended June 30, 2001, we generated less cash from
operations compared to the same period in 2000 mostly because of changes in
working capital requirements.
During the six months ended June 30, 2001, we used more cash for investing
activities compared to the same period in 2000 mostly due to an increase in
investments in new generation facilities, offset in part by the sales of certain
investments.
During the six months ended June 30, 2001, we had more cash from financing
activities compared to the same period of 2000 mostly because we issued more
common stock, short-term borrowings, and long-term debt. We also decreased our
payment of dividends. This was partially offset by the repayment of long-term
debt.
Security Ratings
- ----------------
Independent credit-rating agencies rate Constellation Energy and BGE's
fixed-income securities. The ratings indicate the agencies' assessment of each
company's ability to pay interest, distributions, dividends, and principal on
these securities. These ratings affect how much it will cost each company to
sell these securities. The better the rating, the lower the cost of the
securities to each company when they sell them. Constellation Energy and BGE's
securities ratings at the date of this report are:
Standard Moody's
& Poors Investors Fitch
Rating Group Service IBCA
- ---------------------------------------------------------
Constellation Energy
Unsecured Debt A- A3 A-
BGE
Mortgage Bonds AA- A1 A+
Unsecured Debt A A2 A
Trust Originated
Preferred Securities
and Preference Stock A- "a2" A-
Upon separation of our merchant energy business, the merchant energy
business and BGE Corp. will be rated separately. The ratings for these entities
at separation could differ from Constellation Energy's current ratings. However,
we expect the new ratings to be investment grade. We do not expect BGE's ratings
to be negatively impacted by the separation.
31
Capital Resources
- -----------------
Our business requires a great deal of capital. Our estimated annual amounts for
the years 2001 through 2003, are shown in the table below.
We will continue to have cash requirements for:
o working capital needs including the payments of interest, distributions,
and dividends,
o capital expenditures, and
o the retirement of debt and redemption of preference stock.
Capital requirements for 2001 through 2003 include estimates of funding for
existing and anticipated projects. We continuously review and modify those
estimates.
Actual requirements may vary from the estimates included in the table below
because of a number of factors including:
o regulation, legislation, and competition,
o BGE load requirements,
o environmental protection standards,
o the type and number of projects selected for development,
o the effect of market conditions on those projects,
o the cost and availability of capital, and
o the availability of cash from operations.
Our estimates are also subject to additional factors. Please see the Forward
Looking Statements section on page 37.
Calendar Year Estimates
2001 2002 2003
- ------------------------------------------------------------------ --------- -------- --------
(In millions)
Nonregulated Capital Requirements:
Investment requirements:
Domestic merchant energy $1,402 $ 739 $1,540
Other 39 79 105
- ------------------------------------------------------------------ --------- --------- --------
Total investment requirements 1,441 818 1,645
Retirement of long-term debt 914* 684 209
- ------------------------------------------------------------------ --------- --------- --------
Total nonregulated capital requirements 2,355 1,502 1,854
Utility Capital Requirements:
Construction expenditures:
Regulated electric 163 171 173
Regulated gas 53 52 52
Common 30 26 20
- ------------------------------------------------------------------ --------- --------- --------
Total capital expenditures 246 249 245
Retirement of long-term debt and redemption of
preference stock 394 520 286
- ------------------------------------------------------------------ --------- --------- --------
Total utility capital requirements 640 769 531
- ------------------------------------------------------------------ --------- --------- --------
Total capital requirements $2,995 $2,271 $2,385
================================================================== ========= ========= ========
* Amount does not include $1.1 billion in Constellation Energy debt that we
expect to be redeemed at or prior to business separation
32
Capital Requirements
- --------------------
Domestic Merchant Energy Business
- ---------------------------------
Our domestic merchant energy business will require additional funding for
growing its power marketing operation and developing and acquiring power
projects.
Our domestic merchant energy business investment requirements include the
planned acquisition of the Nine Mile Point nuclear power plant and the
construction of 1,100 megawatts of peaking capacity in the Mid-Atlantic and
Mid-West regions that commenced operations in the summer of 2001. An additional
6,000 megawatts of peaking and combined cycle production facilities are
scheduled for completion in 2002 and beyond in various regions of North America.
For further information see the Strategy section on page 19.
Our domestic merchant energy business investment requirements also include
construction expenditures for improvements to existing generating plants and
costs for replacing the steam generators at Calvert Cliffs.
In March 2000, we received a license extension from the NRC that extends
Calvert Cliffs' operating licenses to 2034 for Unit 1 and 2036 for Unit 2. If we
do not replace the steam generators, we will not be able to operate these units
through our operating license periods. We expect the steam generator replacement
to occur during the 2002 refueling outage for Unit 1 and during the 2003
refueling outage for Unit 2. We estimate these Calvert Cliffs' costs to be:
o $ 61 million in 2001,
o $ 88 million in 2002, and
o $ 60 million in 2003.
Additionally, our estimates of future electric generation construction
expenditures include the costs of complying with Environmental Protection Agency
(EPA), Maryland and Pennsylvania nitrogen oxides emissions (NOx) reduction
regulations as follows:
o $ 83 million in 2001,
o $ 59 million in 2002, and
o $ 7 million in 2003.
We discuss the NOx regulations and timing of expenditures in the
Environmental Matters section of the Notes to Consolidated Financial Statements
on page 14.
Regulated Electric and Gas
- --------------------------
Regulated electric and gas construction expenditures primarily include new
business construction needs and improvements to existing facilities.
Funding for Capital Requirements
- --------------------------------
On October 23, 2000, we announced initiatives designed to advance our growth
strategies in the domestic merchant energy business and a change in our common
stock dividend policy effective April 2001, as discussed in the Strategy section
on page 19.
As part of these initiatives, we expect to redeem all of the outstanding
debt at Constellation Energy at or prior to the separation of our domestic
merchant energy business and remaining businesses. The redemption will occur
through a combination of open market purchases, tender offers, and redemption
calls.
In June, Constellation Energy arranged two revolving credit facilities that
totaled $2.9 billion as discussed in the Financing Activity section of the Notes
to Consolidated Financial Statements on page 13. Prior to or upon separation,
new Constellation Energy will assume these facilities.
Domestic Merchant Energy Business
- ---------------------------------
Funding for the expansion of our domestic merchant energy business is expected
from internally generated funds, commercial paper, long-term debt, equity,
leases, and other financing instruments issued by Constellation Energy and its
subsidiaries. Specifically related to the Nine Mile Point acquisition, one-half
of the purchase price is due at the closing of the transaction and the remainder
is being financed through the sellers in a note to be repaid over five years
with an interest rate of 11.0%. We expect to close the transaction with funds
from available sources at that time. Payments on the note over the five years
are expected to come from internally generated funds. Longer term, we expect to
fund our growth and operating objectives with a mixture of debt and equity with
an overall goal of maintaining an investment grade credit profile.
When our domestic merchant energy business separates from our remaining
businesses, it initially expects to reinvest its earnings to fund its growth and
not to pay a dividend.
Constellation Energy has a commercial paper program where it can issue
short-term notes to fund its nonregulated businesses. To support its commercial
paper program, Constellation Energy maintains three revolving credit agreements
totaling $3.1 billion, of which two facilities can also issue letters of credit.
We entered into two of these agreements during June 2001 as discussed above and
in the Financing Activity section of the Notes to Consolidated Financial
Statements on page 13. In addition, Constellation Energy has access to interim
lines of credit as required from time to time to support its outstanding
commercial paper.
33
BGE
- ---
Funding for utility capital expenditures is expected from internally generated
funds, commercial paper issuances, available capacity under credit facilities,
the issuance of long-term debt, trust securities, or preference stock, and/or
from time to time equity contributions from Constellation Energy.
At March 31, 2001, FERC authorized BGE to issue up to $700 million of
short-term borrowings, including commercial paper. In addition, BGE maintains
$193 million in annual committed bank lines of credit and has $25 million in
bank revolving credit agreements to support the commercial paper program. In
addition, BGE has access to interim lines of credit as required from time to
time to support its outstanding commercial paper.
During the three years from 2001 through 2003, we expect our regulated
utility business to provide at least 130% of the cash needed to meet the capital
requirements for its operations, excluding cash needed to retire debt.
Other Nonregulated Businesses
- -----------------------
BGE Home Products & Services may meet capital requirements through sales of
receivables. ComfortLink has a revolving credit agreement totaling $50 million
to provide liquidity for short-term financial needs.
If we can get a reasonable value for our real estate projects, senior-living
facilities, Latin American operation, and other investments, additional cash may
be obtained by selling them. Our ability to sell or liquidate assets will depend
on market conditions, and we cannot give assurances that these sales or
liquidations could be made. We discuss the real estate and senior-living
facilities operation and market conditions in the Other Nonregulated Businesses
section beginning on page 30.
- --------------------------------------------------------------------------------
Other Matters
- -------------
Environmental Matters
- ---------------------
We are subject to federal, state, and local laws and regulations that work to
improve or maintain the quality of the environment. If certain substances were
disposed of, or released at any of our properties, whether currently operating
or not, these laws and regulations require us to remove or remedy the effect on
the environment. This includes Environmental Protection Agency Superfund sites.
You will find details of our environmental matters in the Environmental Matters
section of the Notes to Consolidated Financial Statements beginning on page 13
and in our 2000 Annual Report on Form 10-K in Item 1. Business - Environmental
Matters. These details include financial information. Some of the information
is about costs that may be material.
Accounting Standards Adopted and Issued
- ---------------------------------------
We discuss recently adopted and issued accounting standards in the Accounting
Standard Adopted and Accounting Standards Issued sections of the Notes to
Consolidated Financial Statements beginning on page 16.
- --------------------------------------------------------------------------------
Item 3. Quantitative and Qualitative Disclosures About Market Risk
- ------------------------------------------------------------------
We discuss the following information related to our market risk:
o risk associated with the purchase and sale of energy in a deregulated
environment as discussed in the Current Issues - Electric Competition
section of Management's Discussion and Analysis on page 20,
o financing activities and an accounting standard adopted in the Notes to
Consolidated Financial Statements on pages 13 and 16, and
o activities of our power marketing business in the Domestic Merchant
Energy Business section of Management's Discussion and Analysis beginning
on page 25.
34
PART II. OTHER INFORMATION
- ---------------------------
Item 1. Legal Proceedings
- --------------------------
Employment Discrimination
- -------------------------
Miller, et al. v. Baltimore Gas and Electric Company, et al. - This action was
filed on September 20, 2000 in the U.S. District Court for the District of
Maryland. Besides BGE, Constellation Energy Group, Constellation Nuclear and
Calvert Cliffs Nuclear Power Plant are also named defendants. The action seeks
class certification for approximately 150 past and present employees and alleges
racial discrimination at Calvert Cliffs Nuclear Power Plant. The amount of
damages is unspecified, however the plaintiffs seek back and front pay, along
with compensatory and punitive damages. We believe this case is without merit.
However, we cannot predict the timing, or outcome, of it or its possible effect
on our, or BGE's, financial results.
Moore v. Constellation Energy Group - This action was filed on October 23,
2000 in the U.S. District Court for the District of Maryland by an employee
alleging employment discrimination. Besides Constellation Energy, BGE and
Constellation Holdings, Inc. were also named defendants. The Equal Employment
Opportunity Commission previously concluded that it was unable to establish a
violation of law. The plaintiff sought, among other things, unspecified monetary
damages and back pay. The court dismissed the case in 2001.
Asbestos
- --------
Since 1993, we have been involved in several actions concerning asbestos. The
actions are based upon the theory of "premises liability," alleging that we knew
of and exposed individuals to an asbestos hazard. The actions relate to two
types of claims.
The first type is direct claims by individuals exposed to asbestos. We
described these claims in BGE's Report on Form 8-K filed August 20, 1993. We are
involved in these claims with approximately 70 other defendants. Approximately
541 individuals that were never employees of BGE each claim $6 million in
damages ($2 million compensatory and $4 million punitive). These claims were
filed in the Circuit Court for Baltimore City, Maryland since the summer of
1993. We do not know the specific facts necessary to estimate our potential
liability for these claims. The specific facts we do not know include:
o the identity of our facilities at which the plaintiffs allegedly worked
as contractors,
o the names of the plaintiff's employers,
o and the date on which the exposure allegedly occurred.
To date, 34 of these cases have been resolved for amounts that were not
significant.
The second type is claims by one manufacturer -- Pittsburgh Corning Corp.
(PCC) -- against us and approximately eight others, as third-party defendants.
On April 17, 2000, PCC declared bankruptcy and we do not expect PCC to prosecute
these claims.
These claims relate to approximately 1,500 individual plaintiffs and were
filed in the Circuit Court for Baltimore City, Maryland in the fall of 1993. To
date, about 350 cases have been resolved, all without any payments by BGE. We do
not know the specific facts necessary to estimate our potential liability for
these claims. The specific facts we do not know include:
o the identity of our facilities containing asbestos manufactured by the
manufacturer,
o the relationship (if any) of each of the individual plaintiffs to us,
o the settlement amounts for any individual plaintiffs who are shown to
have had a relationship to us, and
o the dates on which/places at which the exposure allegedly occurred.
Until the relevant facts for both types of claims are determined, we are
unable to estimate what our liability, if any, might be. Although insurance and
hold harmless agreements from contractors who employed the plaintiffs may cover
a portion of any awards in the actions, our potential liability could be
material.
Restructuring Order
- -------------------
In early December 1999, the Mid-Atlantic Power Supply Association (MAPSA),
Trigen-Baltimore Energy Corporation and Sweetheart Cup Company, Inc. filed
appeals of the Restructuring Order, which were consolidated in the Baltimore
City Circuit Court. MAPSA also filed a motion to delay implementation of the
Restructuring Order, pending a decision on the merits of the appeals by the
court.
On April 21, 2000, the Circuit Court dismissed MAPSA's appeal based on a
lack of standing (the right of a party to bring a lawsuit to court) and denied
its motion for a delay of the Restructuring Order. However, MAPSA filed an
appeal of this decision. On May 24, 2000, the Circuit Court dismissed both the
Trigen and Sweetheart Cup appeals.
35
MAPSA subsequently filed several appeals with the Maryland Court of Special
Appeals, the Maryland Court of Appeals, and the Baltimore City Circuit Court.
The effect of the appeals was to delay the implementation of customer choice in
BGE's service territory.
However, on August 4, 2000, the delay was rescinded and BGE retroactively
adjusted its rates as if customer choice had been implemented July 1, 2000.
On September 29, 2000, the Baltimore City Circuit Court issued an order
upholding the Restructuring Order.
On October 27, 2000, MAPSA filed an appeal with the Maryland Court of Special
Appeals challenging the September 29, 2000 order issued by the Circuit Court.
We believe that this petition is without merit. However, we cannot predict the
timing, or outcome, of this case, which could have a material adverse effect
on our, and BGE's, financial results.
Asset Transfer Order
- --------------------
On July 6, 2000, MAPSA and Shell Energy LLC filed, in the Circuit
Court for Baltimore City, a petition for review and a delay of the Maryland
PSC's order approving the transfer of BGE's generation assets issued on June 19,
2000. The Court denied MAPSA's request for a delay on August 4, 2000, and after
a hearing on the petition on August 23, 2000 issued an order on September 29,
2000 upholding the Maryland PSC's order on the asset transfer. On October 27,
2000, MAPSA filed an appeal with the Maryland Court of Special Appeals
challenging the September 29, 2000 order issued by the Circuit Court. We also
believe that this petition is without merit. However, we cannot predict the
timing, or outcome, of this case, which could have a material adverse effect on
our, and BGE's, financial results.
- --------------------------------------------------------------------------------
Item 4. Submission of Matters to a Vote of Security Holders
- ------------------------------------------------------------
On April 27, 2001, Constellation Energy Group held its annual meeting of
shareholders. At that meeting, the following matters were voted upon:
1. All of the Directors nominated by Constellation Energy Group were selected
as follows:
COMMON SHARES CAST:
------------------
For Against Abstain
--- ------- -------
H. Furlong Baldwin 130,910,754 651,886 2,056,959
James T. Brady 131,016,627 546,014 2,056,959
Beverly B. Byron 130,632,602 930,038 2,056,959
James R. Curtiss 130,664,970 897,670 2,056,959
Jerome W. Geckle 130,763,903 798,737 2,056,959
George L. Russell 130,676,059 886,582 2,056,959
All other directors whose term of office continues as of the date of this
meeting:
Douglas L. Becker Robert J. Hurst
J. Owen Cole Nancy Lampton
Dan A. Colussy Adm. Charles R. Larson
Edward A. Crooke Christian H. Poindexter
Roger W. Gale Mayo A. Shattuck, III
Dr. Freeman A. Hrabowski, III Michael D. Sullivan
2. The ratification of PricewaterhouseCoopers, LLP as independent
accountants was approved. With respect to holders of common stock, the
number of affirmative votes cast were 127,922,255, the number of
negative votes cast were 4,799,834, and the number of abstentions were
1,295,740.
3. The shareholder proposal concerning confidential voting. With respect
to holders of common stock, the number of affirmative votes cast were
50,401,683, the number of negative votes cast were 63,781,894, and the
number of abstentions were 3,420,410.
4. The shareholder proposal concerning investing in clean energy. With
respect to holders of common stock, the number of affirmative votes
cast were 6,537,705, the number of negative votes cast were
106,436,367, and the number of abstentions were 4,630,852.
36
Item 5. Other Information
- --------------------------
Forward Looking Statements
- --------------------------
We make statements in this report that are considered forward looking statements
within the meaning of the Securities Exchange Act of 1934. Sometimes these
statements will contain words such as "believes," "expects," "intends," "plans,"
and other similar words. These statements are not guarantees of our future
performance and are subject to risks, uncertainties and other important factors
that could cause our actual performance or achievements to be materially
different from those we project. These risks, uncertainties, and factors
include, but are not limited to:
o satisfaction of all the conditions precedent to the closing on the
purchase of the Nine Mile Point nuclear power plants, including obtaining
all regulatory approvals,
o obtaining all regulatory approvals necessary to close on the investment
by an affiliate of the Goldman Sachs Group, Inc. in our domestic merchant
energy business and complete the separation of our domestic merchant
energy business from our remaining businesses,
o satisfaction of all conditions precedent to the transaction with Goldman
Sachs,
o general economic, business, and regulatory conditions,
o the pace and nature of deregulation nationwide (including the status of
the California markets),
o competition,
o energy supply and demand,
o federal and state regulations,
o availability, terms, and use of capital,
o nuclear and environmental issues,
o weather,
o implications of the Restructuring Order issued by the Maryland PSC,
including the outcome of the appeal,
o commodity price risk,
o operating our generation assets in a deregulated market without the
benefit of a fuel rate adjustment clause,
o loss of revenue due to customers choosing alternative suppliers,
o higher volatility of earnings and cash flows,
o increased financial requirements of our nonregulated subsidiaries,
o inability to recover all costs associated with providing electric retail
customers service during the electric rate freeze period,
o implications from the transfer of BGE's generation assets and related
liabilities to nonregulated subsidiaries of Constellation Energy,
including the outcome of an appeal of the Maryland PSC's Order regarding
the transfer of generation assets, and
o force majeure (events beyond our control), or other unforeseen events or
delays, such as: acts of nature, changes of laws, labor strikes, work
stoppages, and resource shortages, especially as they could impact plant
construction or operation.
Given these uncertainties, you should not place undue reliance on these forward
looking statements. Please see the other sections of this report and our other
periodic reports filed with the SEC for more information on these factors. These
forward looking statements represent our estimates and assumptions only as of
the date of this report.
- --------------------------------------------------------------------------------
Item 6. Exhibits and Reports on Form 8-K
(a) Exhibit No. 12(a) Constellation Energy Group, Inc. Computation of
Ratio of Earnings to Fixed Charges.
Exhibit No. 12(b) Baltimore Gas and Electric Company Computation of
Ratio of Earnings to Fixed Charges and Computation
of Ratio of Earnings to Combined Fixed Charges and
Preferred and Preference Dividend Requirements.
(b) Reports on Form 8-K for the quarter ended June 30, 2001:
None.
37
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, each
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
CONSTELLATION ENERGY GROUP, INC.
--------------------------------
(Registrant)
BALTIMORE GAS AND ELECTRIC COMPANY
-----------------------------------
(Registrant)
Date: August 13, 2001 /s/ E. Follin Smith
-------------- -----------------------------------
E. Follin Smith, Senior Vice President
on behalf of Constellation Energy Group, Inc.
and as Principal Financial Officer
Date: August 13, 2001 /s/ Thomas F. Brady
-------------- -----------------------------------
Thomas F. Brady, on behalf of
Baltimore Gas and Electric Company
as Principal Financial Officer