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, 2002
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)
750 E. PRATT STREET, BALTIMORE, MARYLAND 21202
----------------------------------------------- -------
(Address of principal executive offices) (Zip Code)
410-234-5000
------------
(Registrants' telephone number, including area code)
250 W. PRATT STREET, BALTIMORE, MARYLAND 21201
----------------------------------------------- -------
(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 164,362,487 shares outstanding of Constellation
Energy Group, Inc. on July 31, 2002.
Baltimore Gas and Electric Company meets the conditions set forth in General
Instruction H(1) (a) and (b) of Form 10-Q and is therefore filing this form in
the reduced disclosure format.
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........................................................................... 21
Application of Critical Accounting Policies............................................ 22
Events of 2002......................................................................... 23
Strategy............................................................................... 26
Business Environment................................................................... 27
Results of Operations.................................................................. 31
Financial Condition.................................................................... 45
Capital Resources...................................................................... 46
Other Matters.......................................................................... 48
Item 3 -- Quantitative and Qualitative Disclosures About Market Risk............................. 48
Part II -- Other Information
Item 1 -- Legal Proceedings...................................................................... 49
Item 4 -- Submission of Matters to a Vote of Security Holders.................................... 50
Item 5 -- Other Information...................................................................... 51
Item 6 -- Exhibits and Reports on Form 8-K....................................................... 51
Signature........................................................................................ 52
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,
2002 2001 2002 2001
- ---------------------------------------------------------------------------------------------------------------------------
(In millions, except per share amounts)
Revenues
Nonregulated revenues $ 449.8 $219.1 $ 808.7 $ 505.2
Regulated electric revenues 480.4 497.4 940.7 989.6
Regulated gas revenues 90.6 109.6 311.4 461.8
- ---------------------------------------------------------------------------------------------------------------------------
Total revenues 1,020.8 826.1 2,060.8 1,956.6
Expenses
Operating expenses 639.0 514.7 1,308.9 1,264.8
Workforce reduction costs 13.3 -- 39.2 --
Loss on sale of turbine 6.0 -- 6.0 --
Depreciation and amortization 117.2 102.0 234.3 205.6
Taxes other than income taxes 63.6 55.5 129.2 113.9
- ---------------------------------------------------------------------------------------------------------------------------
Total expenses 839.1 672.2 1,717.6 1,584.3
Gains on Sale of Investments and Other Assets 3.2 17.1 260.3 33.7
- ---------------------------------------------------------------------------------------------------------------------------
Income from Operations 184.9 171.0 603.5 406.0
Other Income 5.1 4.2 8.9 3.0
- ---------------------------------------------------------------------------------------------------------------------------
Income Before Fixed Charges and Income Taxes 190.0 175.2 612.4 409.0
Fixed Charges
Interest expense 79.5 72.5 146.6 150.5
Interest capitalized and allowance for borrowed funds
used during construction (20.1) (18.8) (31.9) (34.1)
BGE preference stock dividends 3.3 3.3 6.6 6.6
- ---------------------------------------------------------------------------------------------------------------------------
Total fixed charges 62.7 57.0 121.3 123.0
- ---------------------------------------------------------------------------------------------------------------------------
Income Before Income Taxes 127.3 118.2 491.1 286.0
Income Taxes
Current 6.7 36.5 167.7 112.4
Deferred 41.3 8.1 17.4 (1.2)
Investment tax credit adjustments (2.0) (2.0) (4.0) (4.1)
- ---------------------------------------------------------------------------------------------------------------------------
Total income taxes 46.0 42.6 181.1 107.1
- ---------------------------------------------------------------------------------------------------------------------------
Income Before Cumulative Effect of Change in Accounting Principle 81.3 75.6 310.0 178.9
Cumulative Effect of Change in Accounting Principle,
Net of Income Taxes of $5.6 -- -- -- 8.5
- ---------------------------------------------------------------------------------------------------------------------------
Net Income $ 81.3 $ 75.6 $ 310.0 $ 187.4
===========================================================================================================================
Earnings Applicable to Common Stock $ 81.3 $ 75.6 $ 310.0 $ 187.4
===========================================================================================================================
Average Shares of Common Stock Outstanding 164.0 163.7 163.9 157.8
Earnings Per Common Share and Earnings Per Common Share - Assuming
Dilution Before Cumulative Effect of Change in Accounting Principle $ 0.50 $ 0.46 $ 1.89 $ 1.13
Cumulative Effect of Change in Accounting Principle -- -- -- .06
- ---------------------------------------------------------------------------------------------------------------------------
Earnings Per Common Share and
Earnings Per Common Share - Assuming Dilution $ 0.50 $ 0.46 $ 1.89 $ 1.19
Dividends Declared Per Common Share $ 0.24 $ 0.12 $ 0.48 $ 0.24
Consolidated Statements of Comprehensive Income (Unaudited)
Three Months Ended Six Months Ended
June 30, June 30,
2002 2001 2002 2001
- ---------------------------------------------------------------------------------------------------------------------------
(In millions)
Net Income $ 81.3 $ 75.6 $310.0 $187.4
Reclassification adjustment - gains on sale of investments
included in net income, net of taxes -- (0.1) (154.9) (9.6)
Other comprehensive income (loss), net of taxes 30.6 193.7 (17.1) 188.9
- ---------------------------------------------------------------------------------------------------------------------------
Comprehensive Income Before Cumulative Effect of
Change in Accounting Principle 111.9 269.2 138.0 366.7
Cumulative Effect of Change in Accounting Principle,
Net of Income Taxes of $22.6 -- -- -- (35.5)
- ---------------------------------------------------------------------------------------------------------------------------
Comprehensive Income $111.9 $269.2 $138.0 $331.2
===========================================================================================================================
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,
2002* 2001
- -------------------------------------------------------------------------------------------------------------------
(In millions)
Assets
Current Assets
Cash and cash equivalents $ 251.0 $ 72.4
Accounts receivable (net of allowance for uncollectibles
of $24.9 and $22.8, respectively) 757.9 738.9
Trading securities 88.2 178.2
Mark-to-market energy assets 403.0 398.4
Fuel stocks 118.2 108.0
Materials and supplies 213.4 205.3
Prepaid taxes other than income taxes 9.1 93.4
Other 36.6 65.6
- -------------------------------------------------------------------------------------------------------------------
Total current assets 1,877.4 1,860.2
- -------------------------------------------------------------------------------------------------------------------
Investments and Other Assets
Real estate projects and investments 96.9 210.7
Investments in power projects 455.9 499.1
Investment in Orion Power Holdings, Inc. -- 442.5
Financial investments 38.3 60.7
Nuclear decommissioning trust funds 676.4 683.5
Mark-to-market energy assets 1,184.4 1,819.8
Other 275.0 207.4
- -------------------------------------------------------------------------------------------------------------------
Total investments and other assets 2,726.9 3,923.7
- -------------------------------------------------------------------------------------------------------------------
Property, Plant and Equipment
Regulated property, plant and equipment 5,005.1 4,948.7
Nonregulated generation property, plant and equipment 6,676.8 6,551.1
Other nonregulated property, plant and equipment 201.7 192.9
Nuclear fuel (net of amortization) 201.4 169.5
Accumulated depreciation (4,234.9) (4,161.8)
- -------------------------------------------------------------------------------------------------------------------
Net property, plant and equipment 7,850.1 7,700.4
- -------------------------------------------------------------------------------------------------------------------
Deferred Charges
Regulatory assets (net) 428.2 463.8
Other 130.4 129.5
- -------------------------------------------------------------------------------------------------------------------
Total deferred charges 558.6 593.3
- -------------------------------------------------------------------------------------------------------------------
Total Assets $13,013.0 $14,077.6
===================================================================================================================
* 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,
2002* 2001
- -------------------------------------------------------------------------------------------------------------------
(In millions)
Liabilities and Capitalization
Current Liabilities
Short-term borrowings $ 15.5 $ 975.0
Current portion of long-term debt 637.5 1,406.7
Accounts payable 616.4 523.3
Mark-to-market energy liabilities 275.9 323.3
Dividends declared 42.7 23.0
Other 303.5 308.2
- -------------------------------------------------------------------------------------------------------------------
Total current liabilities 1,891.5 3,559.5
- -------------------------------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities
Deferred income taxes 1,335.2 1,431.0
Mark-to-market energy liabilities 802.5 1,476.5
Net pension liability 126.3 173.3
Postretirement and postemployment benefits 347.2 330.9
Deferred investment tax credits 89.6 93.4
Other 249.9 266.9
- -------------------------------------------------------------------------------------------------------------------
Total deferred credits and other liabilities 2,950.7 3,772.0
- -------------------------------------------------------------------------------------------------------------------
Long-term Debt
Long-term debt of Constellation Energy 2,100.0 935.0
Long-term debt of nonregulated businesses 403.1 769.1
First refunding mortgage bonds of BGE 1,040.7 1,040.7
Other long-term debt of BGE 918.1 1,129.6
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 (12.8) (5.2)
Current portion of long-term debt (637.5) (1,406.7)
- -------------------------------------------------------------------------------------------------------------------
Total long-term debt 4,061.6 2,712.5
- -------------------------------------------------------------------------------------------------------------------
BGE Preference Stock Not Subject to Mandatory Redemption 190.0 190.0
Common Shareholders' Equity
Common stock 2,060.1 2,042.2
Retained earnings 1,841.2 1,611.5
Accumulated other comprehensive income 17.9 189.9
- -------------------------------------------------------------------------------------------------------------------
Total common shareholders' equity 3,919.2 3,843.6
- -------------------------------------------------------------------------------------------------------------------
Total capitalization 8,170.8 6,746.1
- -------------------------------------------------------------------------------------------------------------------
Total Liabilities and Capitalization $13,013.0 $14,077.6
===================================================================================================================
* 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,
2002 2001
- -------------------------------------------------------------------------------------------------------------------
(In millions)
Cash Flows From Operating Activities
Net income $310.0 $187.4
Adjustments to reconcile to net cash provided by operating activities
Cumulative effect of change in accounting principle -- (8.5)
Depreciation and amortization 251.4 227.6
Deferred income taxes 17.4 (1.2)
Investment tax credit adjustments (4.0) (4.1)
Deferred fuel costs 24.6 42.8
Pension and postemployment benefits (96.0) 14.0
Gains on sale of investments (260.3) (33.7)
Loss (Gain) on sale of plant assets 6.0 (9.5)
Workforce reduction costs 39.2 --
Equity in earnings of affiliates and joint ventures (net) 43.2 (14.2)
Changes in mark-to-market energy assets and liabilities (90.6) (107.8)
Changes in other current assets 93.4 94.0
Changes in other current liabilities 102.8 (99.0)
Other (103.6) (26.8)
- -------------------------------------------------------------------------------------------------------------------
Net cash provided by operating activities 333.5 261.0
- -------------------------------------------------------------------------------------------------------------------
Cash Flows From Investing Activities
Purchases of property, plant and equipment and other capital expenditures (426.3) (669.6)
Contributions to nuclear decommissioning trust funds (8.8) (13.2)
Purchases of marketable equity securities (0.4) (23.7)
Sales of marketable equity securities 116.8 70.9
Sale of investment in Orion Power Holdings, Inc. 454.1 26.2
Sale of real estate investments 113.8 --
Sale of property, plant and equipment 38.4 49.5
Other investments 7.9 (8.6)
- -------------------------------------------------------------------------------------------------------------------
Net cash provided by (used in) investing activities 295.5 (568.5)
- -------------------------------------------------------------------------------------------------------------------
Cash Flows From Financing Activities
Net (maturity) issuance of short-term borrowings (959.5) 66.6
Proceeds from issuance of
Long-term debt 1,823.0 844.6
Common stock 10.7 504.4
Repayment of long-term debt (1,255.6) (1,106.6)
Common stock dividends paid (59.0) (81.4)
Other (10.0) 9.0
- -------------------------------------------------------------------------------------------------------------------
Net cash (used in) provided by financing activities (450.4) 236.6
- -------------------------------------------------------------------------------------------------------------------
Net Increase (Decrease) in Cash and Cash Equivalents 178.6 (70.9)
Cash and Cash Equivalents at Beginning of Period 72.4 182.7
- -------------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of Period $251.0 $111.8
===================================================================================================================
Other Cash Flow Information
- ---------------------------
Cash paid during the period for:
Interest (net of amounts capitalized) $ 86.2 $116.9
Income taxes $134.1 $133.5
See Notes to Consolidated Financial Statements.
Certain prior-period amounts have been reclassified to conform with the current
period's presentation.
6
BALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARIES
PART 1 - FINANCIAL INFORMATION
Item 1 - Financial Statements
Consolidated Statements of Income (Unaudited)
Three Months Ended Six Months Ended
June 30, June 30,
2002 2001 2002 2001
- -------------------------------------------------------------------------------------------------------------------
(In millions)
Revenues
Electric revenues $480.4 $497.5 $ 940.8 $ 989.8
Gas revenues 92.5 109.6 315.9 467.3
- -------------------------------------------------------------------------------------------------------------------
Total revenues 572.9 607.1 1,256.7 1,457.1
Expenses
Operating expenses:
Electric fuel and purchased energy 273.8 293.9 514.3 559.7
Gas purchased for resale 38.7 52.2 163.0 305.1
Operations and maintenance 81.6 87.5 166.2 173.9
Workforce reduction costs 7.9 -- 28.8 --
Depreciation and amortization 55.8 55.5 112.3 113.2
Taxes other than income taxes 42.0 43.3 86.1 89.3
- -------------------------------------------------------------------------------------------------------------------
Total expenses 499.8 532.4 1,070.7 1,241.2
- -------------------------------------------------------------------------------------------------------------------
Income from Operations 73.1 74.7 186.0 215.9
Other Income (Expense) 0.8 1.5 0.2 (0.8)
- -------------------------------------------------------------------------------------------------------------------
Income Before Fixed Charges and Income Taxes 73.9 76.2 186.2 215.1
Fixed Charges
Interest expense (net) 35.0 39.2 69.5 81.5
Allowance for borrowed funds used during construction (0.4) (1.1) (0.8) (1.4)
- -------------------------------------------------------------------------------------------------------------------
Total fixed charges 34.6 38.1 68.7 80.1
- -------------------------------------------------------------------------------------------------------------------
Income Before Income Taxes 39.3 38.1 117.5 135.0
Income Taxes
Current 19.1 19.5 66.0 60.3
Deferred (2.9) (4.0) (18.3) (5.7)
Investment tax credit adjustments (0.5) (0.6) (1.0) (1.2)
- -------------------------------------------------------------------------------------------------------------------
Total income taxes 15.7 14.9 46.7 53.4
- -------------------------------------------------------------------------------------------------------------------
Net Income 23.6 23.2 70.8 81.6
Preference Stock Dividends 3.3 3.3 6.6 6.6
- -------------------------------------------------------------------------------------------------------------------
Earnings Applicable to Common Stock $ 20.3 $ 19.9 $ 64.2 $ 75.0
===================================================================================================================
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,
2002* 2001
- -------------------------------------------------------------------------------------------------------------------
(In millions)
Assets
Current Assets
Cash and cash equivalents $ 19.8 $ 37.4
Accounts receivable (net of allowance for uncollectibles
of $14.0 and $13.4 respectively) 327.5 295.2
Investment in cash pool, affiliated company 736.1 439.1
Accounts receivable, affiliated companies 134.0 133.4
Fuel stocks 36.1 52.3
Materials and supplies 34.3 33.1
Prepaid taxes other than income taxes 0.9 72.5
Other 4.6 7.6
- -------------------------------------------------------------------------------------------------------------------
Total current assets 1,293.3 1,070.6
- -------------------------------------------------------------------------------------------------------------------
Other Assets
Receivable, affiliated company 13.3 113.3
Other 80.3 74.5
- -------------------------------------------------------------------------------------------------------------------
Total other assets 93.6 187.8
- -------------------------------------------------------------------------------------------------------------------
Utility Plant
Plant in service
Electric 3,389.5 3,349.9
Gas 1,022.8 1,014.4
Common 499.9 498.1
- -------------------------------------------------------------------------------------------------------------------
Total plant in service 4,912.2 4,862.4
Accumulated depreciation (1,812.2) (1,751.4)
- -------------------------------------------------------------------------------------------------------------------
Net plant in service 3,100.0 3,111.0
Construction work in progress 88.4 81.8
Plant held for future use 4.5 4.5
- -------------------------------------------------------------------------------------------------------------------
Net utility plant 3,192.9 3,197.3
- -------------------------------------------------------------------------------------------------------------------
Deferred Charges
Regulatory assets (net) 428.2 463.8
Other 32.2 35.0
- -------------------------------------------------------------------------------------------------------------------
Total deferred charges 460.4 498.8
- -------------------------------------------------------------------------------------------------------------------
Total Assets $5,040.2 $4,954.5
===================================================================================================================
* 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,
2002* 2001
- -------------------------------------------------------------------------------------------------------------------
(In millions)
Liabilities and Capitalization
Current Liabilities
Current portion of long-term debt $ 629.5 $ 666.3
Accounts payable 61.0 63.6
Accounts payable, affiliated companies 136.7 92.6
Customer deposits 52.1 50.0
Accrued taxes 42.1 7.6
Accrued interest 43.0 37.0
Accrued vacation costs 17.9 21.7
Other 17.3 39.2
- -------------------------------------------------------------------------------------------------------------------
Total current liabilities 999.6 978.0
- -------------------------------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities
Deferred income taxes 483.4 503.1
Postretirement and postemployment benefits 276.8 266.1
Deferred investment tax credits 21.6 22.7
Decommissioning of federal uranium enrichment facilities 19.3 19.3
Other 20.9 22.2
- -------------------------------------------------------------------------------------------------------------------
Total deferred credits and other liabilities 822.0 833.4
- -------------------------------------------------------------------------------------------------------------------
Long-term Debt
First refunding mortgage bonds of BGE 1,040.7 1,040.7
Other long-term debt of BGE 918.1 1,129.6
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 59.0 71.0
Unamortized discount and premium (5.1) (3.3)
Current portion of long-term debt (629.5) (666.3)
- -------------------------------------------------------------------------------------------------------------------
Total long-term debt 1,633.2 1,821.7
- -------------------------------------------------------------------------------------------------------------------
Preference Stock Not Subject to Mandatory Redemption 190.0 190.0
Common Shareholder's Equity
Common stock 911.9 711.9
Retained earnings 483.5 419.5
- -------------------------------------------------------------------------------------------------------------------
Total common shareholder's equity 1,395.4 1,131.4
- -------------------------------------------------------------------------------------------------------------------
Total capitalization 3,218.6 3,143.1
- -------------------------------------------------------------------------------------------------------------------
Total Liabilities and Capitalization $5,040.2 $4,954.5
===================================================================================================================
* 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,
2002 2001
- -------------------------------------------------------------------------------------------------------------------
(In millions)
Cash Flows From Operating Activities
Net income $ 70.8 $ 81.6
Adjustments to reconcile to net cash provided by operating activities
Depreciation and amortization 113.8 114.4
Deferred income taxes (18.3) (5.7)
Investment tax credit adjustments (1.0) (1.2)
Deferred fuel costs 24.6 42.8
Pension and postemployment benefits (32.5) 5.8
Workforce reduction costs 28.8 --
Allowance for equity funds used during construction (1.4) (1.4)
Changes in other current assets 149.4 130.9
Changes in other current liabilities 69.8 26.2
Other 5.5 13.0
- -------------------------------------------------------------------------------------------------------------------
Net cash provided by operating activities 409.5 406.4
- -------------------------------------------------------------------------------------------------------------------
Cash Flows From Investing Activities
Utility construction expenditures (excluding AFC) (91.3) (121.3)
Investment in cash pool at parent (297.0) (224.6)
Other (8.5) (9.8)
- -------------------------------------------------------------------------------------------------------------------
Net cash used in investing activities (396.8) (355.7)
- -------------------------------------------------------------------------------------------------------------------
Cash Flows From Financing Activities
Net maturity of short-term borrowings -- (32.1)
Proceeds from issuance of long-term debt 2.0 206.9
Repayment of long-term debt (225.7) (200.0)
Capital contribution from parent 200.0 --
Preference stock dividends paid (6.6) (6.6)
- -------------------------------------------------------------------------------------------------------------------
Net cash used in financing activities (30.3) (31.8)
- -------------------------------------------------------------------------------------------------------------------
Net (Decrease) Increase in Cash and Cash Equivalents (17.6) 18.9
Cash and Cash Equivalents at Beginning of Period 37.4 21.3
- -------------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of Period $ 19.8 $ 40.2
===================================================================================================================
Other Cash Flow Information
- ---------------------------
Cash paid during the period for:
Interest (net of amounts capitalized) $ 68.3 $ 78.2
Income taxes $ 10.3 $ 64.5
See Notes to Consolidated Financial Statements.
Certain prior-period amounts have been reclassified to conform with the current
period's presentation.
10
Notes to Consolidated Financial Statements
- ------------------------------------------
Various factors can have a great impact on our results for interim periods. This
means that the results for this quarter are not necessarily indicative of future
quarters or full year results given the seasonality of our business.
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.
Basis of Presentation
- ---------------------
This Quarterly Report on Form 10-Q is a combined report of Constellation Energy
and BGE. References in this report to "we" and "our" are to Constellation Energy
and its subsidiaries, collectively. References in this report to the "utility
business" are to BGE.
Workforce Reduction Costs
- -------------------------
In the fourth quarter of 2001, we undertook several measures to reduce our
workforce through both voluntary and involuntary means as discussed in Note 2 of
our 2001 Annual Report on Form 10-K.
In accordance with Emerging Issues Task Force Issue (EITF) 94-3, Liability
Recognition for Certain Employee Termination Benefits and Other Costs to Exit an
Activity (including Certain Costs Incurred in a Restructuring), we recognized a
liability of $25.1 million at December 31, 2001 for the targeted number of
involuntary terminations that would have resulted if no employees elected the
age 50 to 54 VSERP. The number of employees that elected to voluntarily retire
under the age 50 to 54 VSERP and how many employees would thereafter be
involuntarily severed was unknown until after the election period of the age 50
to 54 VSERP, which ended in February 2002.
In the first quarter of 2002, 308 employees elected the age 50 to 54 VSERP
for a total cost of $52.9 million. We involuntary severed 129 employees
that resulted in total costs for involuntary severances of $7.3 million.
Accordingly, we reversed $17.8 million of the involuntary severance accrual that
was recorded in 2001 to reflect the employees that elected the age 50 to 54
VSERP.
The $35.1 million of net workforce reduction costs recorded during the first
quarter of 2002 as discussed above, consisted of $25.9 million of additional
expense and $9.2 million recognized by BGE as a regulatory asset related to its
gas business.
In the second quarter of 2002, we recognized an $18.8 million settlement
charge for our basic, qualified pension plan under Statement of Financial
Accounting Standards (SFAS) No. 88, Employers' Accounting for Settlements and
Curtailments of Defined Benefit Pension Plans and for Termination Benefits. This
charge reflects the recognition of actuarial gains and losses associated with
employees who have retired and taken their pension in the form of a lump-sum
payment. In accordance with SFAS No. 88, this settlement charge could not be
recognized with the other workforce reduction costs in the fourth quarter of
2001. Under SFAS No. 88, the settlement charge could not be recognized until
lump-sum pension payments exceeded annual pension plan service and interest
cost, which occurred in the second quarter of 2002.
Partially offsetting the settlement charge, we reversed approximately $2.5
million of previously accrued workforce reduction costs during the second
quarter of 2002. This primarily represented the reversal of education and
outplacement assistance benefits we accrued that employees did not utilize to
the extent expected.
The $16.3 million of net workforce reduction costs recorded in the second
quarter of 2002 as discussed above, consisted of $13.3 million of additional
expense and $3.0 million recognized by BGE as a regulatory asset related to its
gas business.
The following table summarizes the status of that portion of total workforce
reduction costs related to the involuntary severance liability recorded under
EITF 94-3:
(In millions)
Involuntary severance amounts recorded in 2001 $ 25.1
VSERP elections in first quarter of 2002 52.9
Reduction of involuntary severance
accrual for age 50 to 54 VSERP elections (17.8)
---------
Amounts recorded in first quarter of 2002 35.1
Settlement charge in second quarter of 2002 18.8
Reduction of involuntary severance
accrual in second quarter of 2002 (0.6)
---------
Amounts recorded in second quarter of 2002 18.2
Cash severance payments made in 2002 (5.9)
Amount reflected in long-term
pension and postretirement obligations (71.7)
--------
Involuntary severance liability balance at June 30, 2002 $ 0.8
========
The amount reflected in long-term pension and postretirement obligations are
recorded as liabilities in "Net pension liability" and "Postretirement and
postemployment benefits" in our Consolidated Balance Sheets.
Investment in Orion
- -------------------
In February 2002, Reliant Resources, Inc. acquired all of the outstanding shares
of Orion Power Holdings, Inc. (Orion) for $26.80 per share, including the shares
we owned of Orion. We received cash proceeds of $454.1 million and recognized a
gain of $255.5 million pre-tax, or $163.3 million after-tax, on the sale of our
investment.
Investment in Corporate Office Properties Trust (COPT)
- ------------------------------------------------------
In March 2002, we sold all of our COPT equity-method investment, approximately
8.9 million shares, as part of a public offering. We received cash proceeds of
$101.3 million on the sale, which approximated the book value of our investment.
11
Information by Operating Segment
- --------------------------------
Our reportable operating segments are - Merchant Energy, Regulated Electric, and
Regulated Gas:
o Our nonregulated merchant energy business in North America:
- provides power marketing, origination transactions, and risk management
services,
- develops, owns, and operates generating facilities and/or power
projects in North America, and
- provides nuclear consulting services.
o Our regulated electric business purchases, transmits, distributes, and
sells electricity in Maryland, and
o Our regulated gas business purchases, transports, and sells natural gas
in Maryland.
o Our remaining nonregulated businesses:
- provide energy products and services,
- sell and service electric and gas appliances, and heating and air
conditioning systems, engage in home improvements, and sell electricity
and natural gas,
- provide cooling services,
- own financial investments,
- develop, own, and manage real estate,
- own senior-living facilities, and
- own interests in Latin American power generation and distribution
projects and investments.
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. A summary of
information by operating segment is shown in the table on the next page.
As previously discussed in our 2001 Annual Report on Form 10-K, we decided
to sell certain non-core assets and accelerate the exit strategies on other
assets that we will continue to hold and own over the next several years. These
assets include certain real estate, senior-living facilities, and international
power projects. In addition, we initiated a liquidation program for our
financial investments operation and expect to sell substantially all of our
investments in this operation by the end of 2003.
We have reclassified certain prior-period information for comparative
purposes based on our reportable operating segments.
12
Unallocated
Merchant Regulated Regulated Other Corporate
Energy Electric Gas Nonregulated Items and
Business Business Business Businesses Eliminations Consolidated
- --------------------------- -------------- -------------- ------------- -------------- --------------- -------------
(In millions)
For the three months ended June 30,
- -----------------------------------
2002
Unaffiliated revenues $ 318.0 $480.4 $ 90.6 $131.8 $ -- $1,020.8
Intersegment revenues 263.7 -- 1.9 -- (265.6) --
- ---------------------------- ------------- -------------- ------------- -------------- ------------ ----------------
Total revenues 581.7 480.4 92.5 131.8 (265.6) 1,020.8
Net income 56.4 17.4 2.9 4.6 -- 81.3
2001
Unaffiliated revenues $ 102.3 $497.4 $109.6 $116.8 $ -- $ 826.1
Intersegment revenues 281.7 0.1 -- 0.8 (282.6) --
- ---------------------------- ------------- -------------- ------------- -------------- ------------ ----------------
Total revenues 384.0 497.5 109.6 117.6 (282.6) 826.1
Net income 52.4 18.0 3.0 2.2 -- 75.6
For the six months ended June 30,
- ---------------------------------
2002
Unaffiliated revenues $ 556.6 $940.7 $311.4 $252.1 $ -- $2,060.8
Intersegment revenues 491.5 0.1 4.5 -- (496.1) --
- ---------------------------- ------------- -------------- ------------- -------------- ------------ ----------------
Total revenues 1,048.1 940.8 315.9 252.1 (496.1) 2,060.8
Net income 83.4 33.8 30.7 162.1 -- 310.0
2001
Unaffiliated revenues $ 197.2 $989.6 $461.8 $308.0 $ -- $1,956.6
Intersegment revenues 532.5 0.2 5.5 1.9 (540.1) --
- ---------------------------- ------------- -------------- ------------- -------------- ------------ ----------------
Total revenues 729.7 989.8 467.3 309.9 (540.1) 1,956.6
Cumulative effect of
change in accounting
principle -- -- -- 8.5 -- 8.5
Net income 94.8 45.7 31.7 15.2 -- 187.4
13
Financing Activity
- ------------------
Constellation Energy
- --------------------
Constellation Energy issued the following notes during the period from January
1, 2002 through the date of this report:
Date Net
Principal Issued Proceeds
- ------------------------------ --------- -------- ---------
(In millions)
6.35% Fixed Rate Notes $600.0 3/02 $595.4
7.00% Fixed Rate Notes 600.0 3/02 592.9
7.60% Fixed Rate Notes 600.0 3/02 592.8
We used a portion of the net proceeds from the sale of these notes to repay
short-term borrowings, and in April 2002 we used a portion to prepay the
sellers' note of $388.1 million originally issued for the acquisition of Nine
Mile Point Nuclear Station (Nine Mile Point).
In June 2002, Constellation Energy arranged a $640 million 364-day revolving
credit facility and a $640 million three-year revolving credit facility
replacing a $380 million 364-day revolving credit facility. We use these two
facilities to support our issuances of commercial paper and letters of credit
primarily for our merchant energy business.
In addition, a bridge financing facility of $700 million expired in June
2002. This facility was initially established in June 2001 at $2.5 billion
primarily to refinance maturities due or callable specifically in connection
with plans to separate our businesses and to support our issuances of commercial
paper after separation.
Constellation Energy also has an existing $188.5 million revolving credit
facility available to support our issuances of commercial paper and letters of
credit. This facility expires in June 2003.
These revolving credit facilities support the issuances of letters of credit
up to approximately $1.1 billion. At June 30, 2002, letters of credit that
totaled $257.4 million were issued under all of our facilities.
BGE and Nonregulated Businesses
- -------------------------------
In conjunction with the July 1, 2000 transfer of generation assets, BGE
currently is contingently liable for $276 million of the tax exempt debt that
was assigned to nonregulated affiliates of Constellation Energy.
BGE maintains $150.0 million in annual committed bank lines of credit and a
$50 million bank revolving credit agreement to support its commercial paper
program. The $50 million 364-day agreement expires in late 2002. As of June 30,
2002, BGE had no outstanding commercial paper, which results in $200.0 million
in unused credit facilities.
In July 2002, BGE announced a partial call of $11.7 million principal amount
of its 7 1/2% Series, due April 15, 2023 First Refunding Mortgage Bonds in
connection with its annual sinking fund. Bonds called will be redeemed in whole
or in part on August 28, 2002 at the price of 100% of principal, plus accrued
interest from April 15, 2002 to August 28, 2002.
In the future, BGE may purchase some of its long-term debt or preference stock
in the market depending on market conditions and BGE's capital structure.
Please refer to the Financial Condition section of Management's Discussion
and Analysis on page 45 for additional information about the debt of BGE and our
nonregulated businesses.
Commitments
- -----------
Our merchant energy business enters into long-term contracts for:
o the purchase of electric generating capacity and energy,
o the procurement and delivery of fuels to supply our generating plant
requirements, and
o the capacity and transmission rights for the delivery of energy to meet
our physical obligations to our customers.
Our merchant energy business also has committed to contribute additional
capital for our construction program and to make additional loans to some
affiliates, joint ventures, and partnerships in which it has an interest.
Our regulated gas business enters into various long-term contracts for the
procurement, transportation, and storage of gas.
BGE Home Products & Services also has gas and electric purchase commitments
related to sales programs. The gas commitments expire in 2003 and the electric
commitments expire in 2004.
At June 30, 2002, the total amount of commitments was $905.6 million and
they are primarily related to our merchant energy business.
Environmental Matters
- ---------------------
We are subject to regulation by various federal, state, and local authorities
with regard to:
o air quality,
o water quality,
o chemical and waste management and disposal, and
o other environmental matters.
The development (involving site selection, environmental assessments, and
permitting), construction, acquisition, and operation of electric generating,
transmission, and distribution facilities are subject to extensive federal,
state, and local environmental and land use laws and regulations. From the
beginning phases of siting and developing, to the ongoing operation of existing
or new electric generating, transmission, and distribution facilities, our
activities involve compliance with diverse laws and regulations that address
emissions and impacts to air and water, special, protected, and cultural
resources (such as wetlands, endangered species, and archeological/historical
resources), chemical and waste handling, and noise impacts. Our activities
require complex and often lengthy processes to obtain approvals, permits, or
licenses for new, existing, or
14
modified facilities. Additionally, the use and handling of various chemicals or
hazardous materials (including wastes) requires preparation of release
prevention plans and emergency response procedures. As new laws or regulations
are promulgated, we assess their applicability and implement the necessary
modifications to our facilities or their operation, as required.
We discuss the significant matters below.
Clean Air
- ---------
The Clean Air Act affects both existing generating facilities and new projects.
The Clean Air Act and many state laws require significant reductions in SO2
(sulfur dioxide) and NOx (nitrogen oxide) emissions that result from burning
fossil fuels. The Clean Air Act also contains other provisions that could
materially affect some of our projects. Various provisions may require permits,
inspections, or installation of additional pollution control technology. Certain
of these provisions are described in more detail below.
Since our generation portfolio is diverse, both in the mix of fuels used to
generate electricity, as well as in the age of various facilities, the Clean Air
Act requirements have different impacts in terms of compliance costs for each of
our projects. Many of these compliance costs may be substantial, as described in
more detail below. In addition, the Clean Air Act contains many enforcement
tools, ranging from broad investigatory powers to civil, criminal, and
administrative penalties and citizen suits. These enforcement provisions also
include enhanced monitoring, recordkeeping, and reporting requirements for both
existing and new facilities.
The Clean Air Act creates a marketable commodity called an SO2 "allowance."
All non-exempt facilities over 25 megawatts that emit SO2 must obtain allowances
in order to operate after 1999. Each allowance gives the owner the right to emit
one ton of SO2. All non-exempt existing facilities have been allocated
allowances based on a facility's past production and the statutory emission
reduction goals. If additional allowances are needed for new facilities, they
can be purchased from facilities having excess allowances or from SO2 allowance
banks. Our projects comply with the SO2 allowance caps through the purchase of
allowances, use of emission control devices, or by qualifying for exemptions. We
believe that the additional costs of obtaining allowances needed for future
generation projects should not materially affect our ability to build, acquire,
and operate them.
The Clean Air Act also requires states to impose annual operating permit
fees. These fees are based on the tons of pollutants emitted from a generating
facility and vary based on the type of facility. For example, fees will
typically be greater for coal-fired plants than for natural gas-fired plants.
Our portfolio includes coal-fired plants and gas-fired plants, as well as plants
using renewable energy sources such as solar and geothermal, which have far less
emissions. The fees do not significantly increase our costs.
The Ozone Transport Assessment Group, composed of state and local air
regulatory officials from the 37 Mid-Western and Eastern states, has recommended
additional NOx emission (a precursor of ozone) reductions that go beyond current
federal standards. These recommendations include reductions from utility and
industrial boilers during the summer ozone season.
As a result of the Ozone Transport Assessment Group's recommendations, on
October 27, 1998, the Environmental Protection Agency (EPA) issued a rule
requiring 22 Eastern states and the District of Columbia to reduce emissions of
NOx. Among other things, the EPA's rule establishes an ozone season, which runs
from May through September, and a NOx emission budget for each state, including
Maryland and Pennsylvania. The EPA rule requires states to implement controls
sufficient to meet their NOx budget by May 31, 2004. Coal-fired power plants are
a principal target of NOx reductions under this initiative, however, some of our
newer coal-fired plants may already meet the EPA expectations and will not
require the same amount of capital expenditures.
Many of our generation facilities are subject to NOx reduction requirements
under the EPA rule including those located in Maryland and Pennsylvania. This
regulation affects both new and existing facilities causing additional capital
investment. At the Brandon Shores and Wagner facilities, we installed emission
reduction equipment to meet Maryland regulations issued pursuant to EPA's rule.
The owners of the Keystone plant in Pennsylvania are installing emissions
reduction equipment by May 2003 to meet Pennsylvania regulations issued pursuant
to EPA's rule. We estimate our costs for the equipment needed at the Keystone
plant will be approximately $35 million. Through June 30, 2002, we have spent
approximately $12 million.
The EPA established new National Ambient Air Quality Standards for very fine
particulates and revised standards for ozone attainment that were upheld after
various court appeals. While these standards may require increased controls at
our fossil generating plants in the future, implementation 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.
15
Over the past two years, the EPA and several states have filed suits against
a number of coal-fired power plants in Mid-Western and Southern states alleging
violations of the deterioration prevention and non-attainment provisions of the
Clean Air Act's new source review requirements. In 2000 and again in 2002, using
its broad investigatory powers, the EPA requested information relating to
modifications made to our Brandon Shores, Crane, and Wagner plants in Baltimore,
Maryland. The EPA also sent similar, but narrower, information requests to two
of our newer Pennsylvania waste-coal burning plants. We have responded to the
EPA and are waiting to see if the EPA takes any further action. 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.
Although there have not been any new source review-related suits filed against
our facilities, there can be no assurance that any of them will not be the
target of an action in the future. Based on the levels of emissions control that
the EPA and/or states are seeking in these new source review enforcement
actions, we believe that material additional costs and penalties could be
incurred, and/or planned capital expenditures could be accelerated, if the EPA
was successful in any future actions regarding our facilities.
The Clean Air Act requires the EPA to evaluate the public health impacts of
emissions of mercury, a hazardous air pollutant, from coal-fired plants. The EPA
has decided to control mercury emissions from coal-fired plants. Compliance
could be required by approximately 2007. Final regulations are expected to be
issued in 2004 and would affect all coal-fired boilers. The cost of compliance
could be material.
Future initiatives regarding greenhouse gas emissions and global warming
continue to be the subject of much debate. The related Kyoto Protocol was signed
by the United States but has since been rejected by the President who instead
has asked for an 18% decrease in carbon intensity on a voluntary basis. Future
initiatives on this issue and the ultimate effects of the Kyoto Protocol and the
President's initiatives on us are unknown as of the date of this report. As a
result of our diverse fuel portfolio, our contribution to greenhouse gases
varies. Fossil fuel-fired power plants, however, are significant sources of
carbon dioxide emissions, a principal greenhouse gas. Therefore, our compliance
costs with any mandated federal greenhouse gas reductions in the future could be
material.
Clean Water Act
- ---------------
In April 2002, the EPA proposed rules under the Clean Water Act that requires
that cooling water intake structures reflect the best technology available for
minimizing adverse environmental impacts. These rules pertain to existing
utilities and non-utility power producers that currently employ a cooling water
intake structure and whose flow exceeds 50 million gallons per day. A final
action on the proposed rules is expected by August 2003. The proposed rule may
require the installation of additional intake screens or other protective
measures, as well as extensive site specific study and monitoring requirements.
There is also the possibility that the proposed rules may lead to the
installation of cooling towers on some facilities. Our compliance costs
associated with the final rules could be material.
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.
However, based on a Record of Decision issued by the EPA, we can 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.
In late December 1996, BGE signed a consent order with the Maryland
Department of the Environment (MDE) that required it to implement remedial
action plans for contamination at and around the Spring Gardens site, located in
Baltimore, Maryland. The Spring Gardens site was once used to manufacture gas
from coal and oil. BGE submitted the required remedial action plans and they
were approved by the MDE. Based on the these plans, the costs BGE considers to
be probable to remedy the contamination are estimated to total $47 million. BGE
has recorded these costs as a liability on its Consolidated Balance Sheets and
has deferred these costs, net of accumulated amortization and amounts it
recovered from insurance companies, as a regulatory asset. We discuss this
further in Note 6 of our 2001 Annual Report on Form 10-K.
Because of the results of studies at this site, it is reasonably possible
that additional costs could exceed the amount BGE recognized by approximately
$14 million. Through June 30, 2002, BGE has spent approximately $38 million for
remediation at this site. BGE also investigated other small sites where gas was
manufactured in the past. We do not expect the
16
cleanup costs of the remaining smaller sites to have a material effect on our
financial results.
Other potential environmental liabilities and pending environmental actions
are described further in our 2001 Annual Report on Form 10-K in Item 1. Business
- - Environmental Matters.
Storage of Spent Nuclear Fuel
- -----------------------------
As previously discussed in our 2001 Annual Report on Form 10-K, on February 14,
2002, the Secretary of Energy submitted to the President a recommendation for
approval of the Yucca Mountain site for the development of a nuclear waste
repository for the disposal of spent nuclear fuel and high level nuclear waste
from the nation's defense activities. In July 2002, the President signed a
resolution approving the Yucca Mountain site after receiving the approval of
this site from the U.S. Senate and House of Representatives. This action allows
the Department of Energy to apply to the Nuclear Regulatory Commission (NRC) to
license the project. The facility is expected to open in 2010. However, the
opening of Yucca Mountain could be delayed due to litigation related to the site
as a permanent repository for spent nuclear fuel.
Insurance
- ---------
Nuclear Insurance
- -----------------
We maintain nuclear insurance coverage for Calvert Cliffs and Nine Mile Point in
four program areas: liability, worker radiation claims, property, and accidental
outage. However, these policies have certain industry standard exclusions, such
as ordinary wear and tear, and war. Terrorist acts, while not excluded from the
property and accidental outage policies, are covered as a common occurrence,
meaning that if terrorist acts occur against one or more commercial nuclear
power plants insured by our insurance company within a 12-month period, they
will be treated as one event and the owners of the plants will share one full
limit of each type of policy (currently $3.24 billion). Claims that arise out of
terrorist acts are also covered by our nuclear liability and worker radiation
policies. However, these policies are subject to one industry aggregate limit
(currently $200 million) for the risk of terrorism. Unlike the property and
accidental outage policies, an industry-wide retrospective assessment program
applies above the industry limit.
If there were an accident or an extended outage at any unit of Calvert
Cliffs or Nine Mile Point, it could have a substantial adverse financial effect
on us.
Nuclear Liability Insurance
- ---------------------------
Pursuant to the Price-Anderson Act, we are required to insure against public
liability claims resulting from nuclear incidents to the full limit of
approximately $9.5 billion. We have purchased the maximum available commercial
insurance of $200 million, and the remaining $9.3 billion is provided through
mandatory participation in an industry-wide retrospective assessment program.
Under this retrospective assessment program, we can be assessed up to $352.4
million per incident at any commercial reactor in the country, payable at no
more than $40 million per incident per year. This assessment also applies in
excess of our worker radiation claims insurance and is subject to inflation and
state premium taxes. In addition, the U.S. Congress could impose additional
revenue-raising measures to pay claims.
Some of the provisions of this Act expire in August 2002, and the Act is
subject to change if those provisions are extended. A renewal bill was passed by
the U.S. House of Representatives that proposes a change in the annual
retrospective premium limit from $10 million to $15 million per reactor per
incident and a change in the maximum potential assessment from $88.1 million to
$98.7 million per reactor per incident. If approved, these changes would
increase the amount we could be assessed to $394.8 million per incident, payable
at no more than $60 million per incident per year. The Price-Anderson Act will
remain in effect in its current form until it is renewed. We do not know what
impact any other changes to the Act may have on us until a final resolution is
reached.
Worker Radiation Claims Insurance
- ---------------------------------
We participate in the American Nuclear Insurers Master Worker Program that
provides coverage for worker tort claims filed for radiation injuries. Effective
January 1, 1998, this program was modified to provide coverage to all workers
whose nuclear-related employment began on or after the commencement date of
reactor operations. Waiving the right to make additional claims under the old
policy was a condition for acceptance under the new policy. We describe 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.
17
o All nuclear worker claims reported prior to January 1, 1998 are still
covered by the old policy. Insureds under the old policies, with no
current operations, are not required to purchase the new policy described
on the previous page, and may still make claims against the old policies
through 2007. If radiation injury claims under these old policies exceed
the policy reserves, all policyholders could be retroactively assessed,
with our share being up to $6.3 million.
The sellers of Nine Mile Point retain the liabilities for existing and
potential claims that occurred prior to November 7, 2001. In addition, the Long
Island Power Authority, which continues to own 18% of Unit 2 at Nine Mile Point,
is obligated to assume its pro rata share of any liabilities for retrospective
premiums and other premiums assessments. If claims under these policies exceed
the coverage limits, the provisions of the Price-Anderson Act would apply.
Nuclear Property Insurance
- --------------------------
Our policies provide $500 million in primary and an additional $2.25 billion in
excess coverage for property damage, decontamination, and premature
decommissioning liability for Calvert Cliffs or Nine Mile Point. 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 $56.2
million.
Accidental Nuclear Outage Insurance
- -----------------------------------
Our policies provide indemnification on a weekly basis resulting from an
accidental outage of a nuclear unit. Initial coverage begins after a 12-week
deductible period and continues at 100% of the weekly indemnity limit for 52
weeks and 80% of the weekly indemnity limit for the next 110 weeks. Our coverage
is up to $490.0 million per unit at Calvert Cliffs, $335.4 million for Unit 1 of
Nine Mile Point, and $412.6 million for Unit 2 of Nine Mile Point. This amount
can be reduced by up to $98.0 million per unit at Calvert Cliffs and $82.5
million for Nine Mile Point if an outage at either plant is caused by a single
insured physical damage loss.
Non-Nuclear Property Insurance
- ------------------------------
On July 1, 2002, we renewed our non-nuclear property insurance. Since September
11, 2001, conventional property insurers have excluded or restricted coverage
for property damage losses arising from acts of terrorism. Our new conventional
property insurance provides a $5 million limit for acts of terrorism. In
addition, we elected to participate in an industry mutual insurance program that
provides property damage coverage for losses resulting from acts of terrorism
above the $5 million provided by our conventional property insurer. This program
provides limits of $50 million per occurrence and is subject to a term aggregate
limit of $100 million that expires May 1, 2003. These limits are shared among
all companies participating in the program. The mutual insurer may renew this
program depending upon the availability of reinsurance at the program's
expiration. If terrorist acts at any of our facilities result in a loss
exceeding this coverage, it could have a significant adverse impact on our
financial results.
California Power Agreements
- ---------------------------
As a result of ongoing litigation before the FERC regarding sales into the spot
markets of the California Independent System Operator and Power Exchange, we may
be required to pay refunds of between $3 and $4 million for transactions that we
entered into with these entities for the period between October 2000 and June
2001.
As part of the settlement agreement we signed with various California
entities in regard to our High Desert Power Project discussed in the Events of
2002 section on page 24, those California entities disclaimed any right they may
have to a refund. We do not know if we will still be required to pay any refunds
to the California entities party to the settlement agreement.
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 100% of the energy and capacity required to meet its standard offer service
obligations for the first three years of the transition period, and 90% of the
energy and capacity for the final three years (July 1, 2003 through June 30,
2006) 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 $273.8 million for the quarter ended June 30, 2002
compared to $281.2 million for the same period in 2001 and $514.3 million for
the six months ended June 30, 2002 compared to $532.5 million for the same
period in 2001.
In addition, BGE is charged by Constellation Energy for certain corporate
functions. Certain costs are directly assigned 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
18
entity. These costs were approximately $5.7 million for the quarter ended June
30, 2002 compared to $6.4 million for the same period in 2001, and $9.4 million
for the six months ended June 30, 2002, compared to $10.1 million for the same
period in 2001.
Balance Sheet
- -------------
BGE participates in a cash pool under a Master Demand Note agreement with
Constellation Energy. Under this arrangement, participating subsidiaries may
invest in or borrow from the pool at market interest rates. Constellation Energy
administers the pool and invests excess cash in short-term investments or issues
commercial paper to manage consolidated cash requirements. BGE had invested
$736.1 million at June 30, 2002 and $439.1 million at December 31, 2001 under
this arrangement.
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.
SFAS No. 133 Hedging Activities
- -------------------------------
We are exposed to market risk, including changes in interest rates and the
impact of market fluctuations in the price and transportation costs of
electricity, natural gas, and other commodities. We discuss our market risk in
more detail in our 2001 Annual Report on Form 10-K.
Interest Rates
- --------------
We use interest rate swaps to manage our interest rate exposures associated with
new debt issuances. These swaps are designated as cash-flow hedges under SFAS
No. 133, Accounting for Derivative Instruments and Hedging Activities with
gains, net of associated deferred income tax effects, recorded in "Accumulated
other comprehensive income" in our Consolidated Balance Sheets, in anticipation
of planned financing transactions. Any gain or loss on the hedges is
reclassified from "Accumulated other comprehensive income" into "Interest
expense" and included in earnings during the periods in which the interest
payments being hedged occur.
Prior to the March 2002 issuance of $1.8 billion of debt as discussed in the
Financing Activity section on page 14, we entered into various forward starting
interest rate swap contracts to manage our interest rate exposure related to
this debt issuance. In 2001, we entered into swaps that had notional or contract
amounts that totaled $800 million with an average rate of 4.9%. In the first
quarter of 2002, we entered into additional forward starting interest rate swaps
with notional amounts that totaled $700 million with an average rate of 5.9%.
All of these swap contracts expired at the end of March 2002 for a gain of
$53.7 million. We will reclassify this gain from "Accumulated other
comprehensive income" into "Interest expense" and include it in earnings during
the periods in which the hedged interest payments occur.
Commodity Prices
- ----------------
At June 30, 2002, our merchant energy business had designated certain
fixed-price forward sale contracts as cash-flow hedges of forecasted
transactions for the years 2002 through 2010 under SFAS No. 133.
Under the provisions of SFAS No. 133, we record gains and losses on energy
derivative contracts designated as cash-flow hedges of forecasted transactions
in "Accumulated other comprehensive income" in our Consolidated Balance Sheets
prior to the settlement of the anticipated hedged physical transaction. We
reclassify these gains or losses into earnings upon settlement of the underlying
hedged transaction. We record derivatives used for hedging activities from our
merchant energy business in "Other assets," and in "Other deferred credits and
other liabilities," in our Consolidated Balance Sheets.
At June 30, 2002, our merchant energy business recorded net unrealized
pre-tax gains of $49.7 million on these hedges, net of associated deferred
income tax effects, in "Accumulated other comprehensive income." We expect to
reclassify $12.4 million of net pre-tax gains on cash-flow hedges from
"Accumulated other comprehensive income" into earnings during the next twelve
months based on the market prices at June 30, 2002. However, the actual amount
reclassified into earnings could vary from the amounts recorded at June 30, 2002
due to future changes in market prices. We recognized into earnings a pre-tax
gain of $0.4 million for the quarter and a pre-tax loss of $1.7 million for the
six months ended June 30, 2002 related to the ineffective portion of our hedges.
Physical Delivery Business
- --------------------------
As a result of the changes in our organization and senior management in late
2001, including the cancellation of business separation and the termination of
the power business services agreement with Goldman Sachs, we re-evaluated our
load-serving activities in Texas and New England. We determined that since we
manage these activities as a physical delivery business rather than a trading
business, it is appropriate to apply accrual accounting for these activities.
Re-designation of Texas Business
- --------------------------------
During February 2002, we re-designated our Texas load-serving business from
trading to non-trading (accrual accounting) under EITF 98-10, Accounting for
Contracts Involved in Energy Trading and Risk Management Activities. In Texas,
we serve our customers' energy requirements using physically
19
delivering power purchase agreements and our Rio Nogales plant. Further, changes
in the Texas market in mid-February 2002 significantly reduced trading activity
and the ability to manage load-serving transactions through trading activities.
Based upon these factors, we began to manage our Texas load-serving
activities as a physical delivery business separate from our trading activities
and re-designated these activities as non-trading effective February 15, 2002.
We believe that this designation more accurately reflects the substance of our
Texas load-serving physical delivery business.
At the time of this change in designation, we reclassified the fair value of
load-serving contracts and physically delivering power purchase agreements in
Texas from "Mark-to-market energy assets and liabilities" to "Other assets" and
"Other deferred credits and other liabilities." The contracts reclassified
consisted of gross assets of $78 million and gross liabilities of $15 million,
or a net asset of $63 million.
Beginning February 15, 2002, the results of our Texas load-serving business
are included in "Nonregulated revenues" on a gross basis as power is delivered
to our customers. In addition, the costs associated with our Texas load-serving
business are included in "Operating expenses" when incurred. Prior to that date,
the results of these activities were reported on a net basis as part of
origination and risk management revenues included in "Nonregulated revenues."
New England Load-Serving Business
- ---------------------------------
The New England load-serving business consists primarily of contracts to serve
the full energy and capacity requirements of electric distribution utilities and
associated power purchase agreements to supply our customers' requirements. We
manage this business primarily to assure profitable delivery of customers'
energy requirements rather than as a traditional trading activity. Because EITF
98-10 significantly limits the circumstances under which contracts previously
designated as a trading activity may be re-designated as non-trading, we
presently must continue to include contracts entered into prior to the second
quarter of 2002 in our trading activities portfolio that is subject to
mark-to-market accounting under EITF 98-10. However, we use accrual accounting
for New England load-serving transactions and associated power purchase
agreements entered into beginning in the second quarter of 2002.
Accounting Standards Issued
- ---------------------------
In 2001, the Financial Accounting Standards Board (FASB) issued SFAS No. 143,
Accounting for Obligations Associated with the Retirement of Long-Lived Assets.
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.
In July 2002, the FASB issued SFAS No. 146, Accounting for Exit or Disposal
Activities. SFAS No. 146 addresses significant issues regarding the recognition,
measurement, and reporting of costs that are associated with exit and disposal
activities, including restructuring activities that are currently accounted for
under EITF 94-3. The provisions of the Statement will be effective for disposal
activities initiated after December 31, 2002, with early application encouraged.
Currently, we are evaluating this statement and its implications on any future
exit or disposal initiative.
20
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 North American
energy company that conducts its business through various subsidiaries including
a merchant energy business and Baltimore Gas and Electric Company (BGE). Our
merchant energy business generates and markets wholesale electricity in North
America. BGE is an electric and gas public utility 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 12.
References in this report to "we" and "our" are to Constellation Energy and
its subsidiaries, collectively. References in this report to the "utility
business" are 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 merchant energy business. We discuss the
deregulation of electric generation in the Business Environment section on page
27.
Our merchant energy business includes:
o fossil, nuclear, and hydroelectric generating facilities, interests in
power projects in North America, and nuclear consulting services, and
o power marketing, origination transactions, and risk management
services.
BGE is a regulated electric and gas public transmission and distribution
utility company.
Our other nonregulated businesses include:
o energy products and services,
o home products, commercial building systems, and residential and
commercial electric and gas retail marketing,
o a general partnership, in which BGE is a partner, that provides cooling
services for commercial customers in Baltimore,
o financial investments,
o real estate and senior-living facilities, and
o interests in Latin American power generation and distribution projects
and investments.
As previously discussed in our 2001 Annual Report on Form 10-K and in our
Other Nonregulated Businesses section on page 44, we decided to sell certain
non-core assets and accelerate the exit strategies on other assets that we will
continue to hold and own over the next several years. These assets include
certain real estate, senior-living facilities, and international power projects.
In addition, we initiated a liquidation program for our financial investments
operation and expect to sell substantially all of our investments in this
operation by the end of 2003.
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, 2002 and 2001. We analyze and explain
the differences between periods in the specific line items of the Consolidated
Statements of Income.
21
Application of Critical Accounting Policies
- -------------------------------------------
Our discussion and analysis of financial condition and results of operations are
based on our consolidated financial statements that were prepared in accordance
with accounting principles generally accepted in the United States of America.
Management makes estimates and assumptions when preparing financial statements.
These estimates and assumptions affect various matters, including:
o our reported amounts of assets and liabilities in our Consolidated
Balance Sheets at the dates of the financial statements,
o our disclosure of contingent assets and liabilities at the dates of the
financial statements, and
o our reported amounts of revenues and expenses in our Consolidated
Statements of Income during the reporting periods.
These estimates involve judgments with respect to, among other things,
future economic factors that are difficult to predict and are beyond
management's control. As a result, actual amounts could materially differ from
these estimates.
The Securities and Exchange Commission (SEC) issued disclosure guidance for
accounting policies that management believes are most "critical." The SEC
defines these critical accounting policies as those that are both most important
to the portrayal of a company's financial condition and results and require
management's most difficult, subjective, or complex judgment, often as a result
of the need to make estimates about the effect of matters that are inherently
uncertain and may change in subsequent periods.
Management believes the following accounting policies represent critical
accounting policies as defined by the SEC. We discuss our significant accounting
policies, including those that do not require management to make difficult,
subjective, or complex judgments or estimates, in Note 1 of our 2001 Annual
Report on Form 10-K.
Revenue Recognition / Mark-to-Market Method of Accounting
- ---------------------------------------------------------
Our origination and risk management operation, Constellation Power Source,
engages in power marketing activities that include origination transactions and
risk management activities using contracts for energy, other energy-related
commodities, and related derivative contracts. We use the mark-to-market method
of accounting for portions of Constellation Power Source's activities as
required by Emerging Issues Task Force Issue (EITF) 98-10, Accounting for
Contracts Involved in Energy Trading and Risk Management Activities. We record
all other revenues in the period earned on an accrual basis for services
rendered, commodities or products delivered, or contracts settled. We also
designate certain fixed-price forward sales contracts as cash-flow hedges of
forecasted transactions under the provisions of Statement of Financial
Accounting Standards (SFAS) No. 133, Accounting for Derivative Instruments and
Hedging Activities, as discussed in more detail in the Notes to Consolidated
Financial Statements - SFAS No. 133 - Hedging Activities section on page 19.
Under the mark-to-market method of accounting, we record the fair value of
commodity and derivative contracts as mark-to-market energy assets and
liabilities at the time of contract execution. We record reserves to reflect
uncertainties associated with certain estimates inherent in the determination of
fair value. Origination and risk management revenues include:
o the fair value of new transactions at origination,
o unrealized gains and losses from changes in the fair value of open
positions,
o net gains and losses from realized transactions, and
o changes in reserves.
We record the changes in mark-to-market energy assets and liabilities on a
net basis in "Nonregulated revenues" in our Consolidated Statements of Income.
Mark-to-market energy assets and liabilities are comprised of a combination of
energy and energy-related derivative and non-derivative contracts. While some of
these contracts represent commodities or instruments for which prices are
available from external sources, other commodities and certain contracts are not
actively traded and are valued using modeling techniques to determine expected
future market prices, contract quantities, or both. The market prices and
quantities used to determine fair value reflect management's best estimate
considering various factors. However, it is possible that future market prices
and actual contract quantities could vary from those used in recording
mark-to-market energy assets and liabilities, and such variations could be
material.
Certain power marketing and risk management transactions entered into under
master agreements and other arrangements provide our merchant energy business
with a right of setoff in the event of bankruptcy or default by the
counterparty. We report such transactions net in our Consolidated Balance Sheets
in accordance with FASB Interpretation No. 39, Offsetting of Amounts Related to
Certain Contracts.
The EITF is re-examining the accounting for energy trading contracts. In
June 2002, the EITF reached a consensus requiring gains and losses on energy
trading contracts (whether realized or unrealized) to be reported as revenue on
a net basis in the income statement. This consensus is applicable for periods
ending after July 15, 2002 and requires restatement of prior periods. This
consensus will not have an impact on our financial statements because we record
gains and losses on energy trading contracts on a net revenue basis as
previously discussed.
22
During the remainder of 2002, the EITF is scheduled to consider other energy
trading accounting issues, including:
o the types of contracts included in the scope of energy trading activities
and subject to mark-to-market accounting,
o techniques for determining the fair value of energy trading contracts for
which fair value is based upon models, and
o whether gains should be recorded in the income statement at the inception
of contracts for which fair value is based upon models.
As a result of this review, the EITF may change what types of energy
contracts are considered to be trading or the techniques for determining the
fair value of energy trading contracts, including limiting or prohibiting the
recognition of gains at the inception of contracts. We cannot predict whether or
how the EITF may change the accounting for energy trading contracts, but any
changes it may require could have a significant impact on our financial results.
The EITF is scheduled to complete its consideration of these issues prior to the
end of 2002 so that any consensus it reaches can be applied in calendar year
2002 financial statements.
We discuss the impact of mark-to-market accounting on our financial results
in the Results of Operations -- Merchant Energy Business section on page 32.
Evaluation of Assets for Impairment and Other Than Temporary Decline in Value
- -----------------------------------------------------------------------------
We are required to evaluate certain assets that have long lives (generating
property and equipment and real estate) to determine if they are impaired if
certain conditions exist. We determine if long-lived assets are impaired by
comparing their undiscounted expected future cash flows to their carrying amount
in our accounting records. We would record an impairment loss under two cases.
The first is if the undiscounted expected future cash flows from an asset were
less than the carrying amount of the asset. The second is if we change our
intent about an asset from an intent to hold to an intent to sell and the market
value is less than the investment in the asset. Additionally, we evaluate our
equity-method investments to determine whether they have experienced a loss in
value that is considered other than a temporary decline in value.
We use our best estimates in making these evaluations and consider various
factors, including forward price curves for energy, fuel costs, and operating
costs. However, actual future market prices and project costs could vary from
those used in our impairment evaluations, and the impact of such variations
could be material.
Events of 2002
- --------------
Dividend Increase
- -----------------
On January 30, 2002, we announced an increase in our quarterly dividend to 24
cents per share on our common stock payable April 1, 2002 to holders of record
on March 11, 2002. This is equivalent to an annual rate of 96 cents per share.
Previously, our quarterly dividend on our common stock was 12 cents per share,
equivalent to an annual rate of 48 cents per share.
Investment in Orion
- -------------------
In February 2002, Reliant Resources, Inc. acquired all of the outstanding shares
of Orion Power Holdings, Inc. (Orion) for $26.80 per share, including the shares
we owned of Orion. We received cash proceeds of $454.1 million and recognized a
gain of $255.5 million pre-tax, or $163.3 million after-tax, on the sale of our
investment.
Investment in Corporate Office Properties Trust (COPT)
- ------------------------------------------------------
In March 2002, we sold all of our COPT equity-method investment, approximately
8.9 million shares, as part of a public offering. We received cash proceeds of
$101.3 million on the sale, which approximated the book value of our investment.
Workforce Reduction Costs
- -------------------------
As discussed in Notes to Consolidated Financial Statements on page 11, we
undertook several measures to reduce our workforce through both voluntary and
involuntary means in the fourth quarter of 2001.
In the first quarter of 2002, 308 employees elected the age 50 to 54 VSERP
for a total cost of $52.9 million. We involuntary severed 129 employees
that resulted in a total cost for the involuntary severance program of $7.3
million. Accordingly, we reversed $17.8 million of the involuntary
severance accrual that was recorded in 2001 to reflect the employees that
elected the age 50 to 54 VSERP.
The $35.1 million of net workforce reduction costs recorded in the first
quarter of 2002 as discussed above, consisted of $25.9 million of additional
expense and $9.2 million recognized by BGE as a regulatory asset related to its
gas business.
In the second quarter of 2002, we recognized an $18.8 million settlement
charge for our basic, qualified pension plan under SFAS No. 88, Employers'
Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and
for Termination Benefits. This charge reflects the recognition of actuarial
gains and losses associated with employees who have retired and taken their
pension in the form of a lump-sum payment. In accordance with SFAS No. 88,
this settlement charge could not be recognized with
23
the other workforce reduction costs in the fourth quarter of 2001. Under SFAS
No. 88, the settlement charge could not be recognized until lump-sum pension
payments exceeded annual pension plan service and interest cost, which occurred
in the second quarter of 2002. We expect to recognize approximately $5 million
of addition settlement charges over the remainder of 2002 as more lump-sum
pension payments occur.
Partially offsetting the settlement charge, we reversed approximately $2.5
million of previously accrued workforce reduction costs during the second
quarter of 2002. This primarily represented the reversal of education and
outplacement assistance benefits we accrued that employees did not utilize to
the extent expected.
The $16.3 million of net workforce reduction costs recorded in the second
quarter of 2002 as discussed above, consisted of $13.3 million of additional
expense and $3.0 million recognized by BGE as a regulatory asset related to its
gas business.
Once our workforce reduction efforts to date have been fully implemented,
we expect ongoing, full year cost savings of approximately $72 million. These
savings will be realized in either labor included in operating expenses or
capitalized labor, partially offset by other increases in operating or capital
costs. We will continue to examine other cost-cutting measures to remain
competitive in our business environment.
Pension Plan Assets
- -------------------
As a result of declines in the financial markets, our actual return on pension
plan assets was a loss of approximately 5% through June 30, 2002. If our return
on pension plan assets remains unchanged through the end of 2002, we expect to
record an after-tax charge to equity of approximately $80 million at December
31, 2002 as a result of increasing our additional minimum pension liability.
This amount will be determined by the actual return on pension plan assets for
2002, which depends on the performance of the financial markets, and our
discount rate assumption, which depends on year-end interest rates. As a result,
the charge to equity could change materially.
Debt Issuance
- -------------
In March 2002, we issued $1.8 billion of debt as discussed in the Notes to
Consolidated Financial Statements - Financing Activity section on page 14. The
proceeds were used to repay short-term borrowings and prepay the sellers'
financed note of $388.1 million related to our purchase of Nine Mile Point
Nuclear Station (Nine Mile Point) in April of 2002.
Renegotiations of our High Desert Power Contracts
- -------------------------------------------------
We are currently leasing and supervising the construction of the High Desert
Power Project. The project is scheduled for completion in 2003. In April 2002,
we amended our High Desert Power Project long-term power sales agreement with
the State of California to provide revised pricing and more flexibility in the
amount of electricity purchased from the plant by the California Department of
Water Resources (CDWR) and the timing of such purchases. This amended agreement
provides the State of California with the flexibility they desired, while
preserving our overall economics and reducing our regulatory, fuel, and legal
risks.
We also signed a comprehensive settlement agreement with the CDWR, the
California Energy Oversight Board (EOB), the California Public Utilities
Commission (CPUC), the California Attorney General, and the Governor of
California by which each of these parties agreed to release claims against us
arising out of the original and renegotiated contracts.
Under the settlement agreement, the California parties filed with the
Federal Energy Regulatory Commission (FERC) to withdraw us from the regulatory
complaint filed at the FERC by the CPUC and EOB against all holders of long-term
power contracts alleging that the rates charged under the original contracts
were not just and reasonable. In addition, the California parties who filed a
complaint at the FERC alleging that the participants (including Constellation
Power Source) who participated in the California Independent System Operator and
California Power Exchange were in violation of their market-based rates
authority filed to withdraw us from that regulatory complaint. We agreed to pay
$1.25 million into a school and public buildings energy retrofit fund and
another $1.25 million to the Attorney General's office in order to conclude this
overall comprehensive settlement package.
The new contract is a "tolling" structure, which provides CDWR the right,
but not the obligation, to purchase power at a price linked to the variable cost
of production, under which the CDWR will pay a fixed amount per month and pay
for fuel and other variable costs. During the term of the contract, which runs
for 7 years and nine months from the commercial operation date of the plant, the
High Desert Power Project will provide energy exclusively to the CDWR.
The High Desert Power Project uses an off-balance sheet financing structure
through a special-purpose entity (SPE) that currently qualifies as an operating
lease. In July 2002, the FASB issued an exposure draft for a new accounting
interpretation that if adopted as drafted potentially would impact the
accounting for, but not the cash flows associated with, our High Desert
operating lease and the related SPE. Under the interpretation, we may be
required to consolidate the SPE in our Consolidated Balance Sheets. We would
have recorded approximately $377.2 million of development, construction, and
capitalized financing costs as an asset and the related financial obligations as
a liability in our Consolidated Balance Sheets had we consolidated this project
at June 30, 2002.
We discuss our High Desert project in more detail in the Capital Resources
section on page 46.
24
Acquisition of NewEnergy
- ------------------------
In June 2002, we announced the execution of an agreement to purchase AES
NewEnergy, Inc. (NewEnergy), a subsidiary of AES Corporation. NewEnergy is a
leading national provider of electricity, natural gas, and energy services,
serving 4,000 megawatts (MW) of load associated with large commercial and
industrial customers in competitive energy markets including the Northeast,
Mid-Atlantic, Midwest, Texas and California.
Under the terms of the agreement, we will acquire 100% ownership of
NewEnergy for $240 million. The purchase price will be adjusted for any change
in NewEnergy's working capital as specified in the purchase agreement and its
actual working capital at the time of closing. NewEnergy's working capital as
provided in the purchase agreement included $64 million of cash and marketable
securities. The transaction is expected to close before year-end. The FERC
approved the purchase and the waiting period ended under the Hart-Scott-Rodino
Antitrust Improvement Act. The purchase remains subject to customary closing
conditions.
Generating Facilities Commence Operations
- -----------------------------------------
The following generating facilities commenced operations beginning in the second
quarter of 2002. Our origination and risk management operation manages the
output of these plants.
Capacity Primary
Plant Location (MW) Type Fuel
- -------------- ------------- --------- ------------ -------
Combined
Rio Nogales Seguin, TX 800 Cycle Gas
Combustion
Oleander Brevard Co., FL 510* Turbine Gas
*As of the date of this report, one of the four units has not been placed in
service. We expect the final unit to be placed in service in the third quarter
of 2002. The total capacity of the Oleander plant will be 680 megawatts.
As discussed in our Re-designation of Texas Business section on page 38, the
output from the Rio Nogales project, along with power purchase agreements, is
used to meet our customers' energy requirements in Texas.
The Oleander project sells 75% of its output to Seminole Electric
Cooperative of Tampa, Florida for seven years. Power sales for 50% of the power
begin in December 2002, while power sales for the other 25% begin in May 2003.
Additionally, Oleander has signed two power purchase agreements with Florida
Power and Light Company that began in June 2002. The first contract to purchase
25% of the plant output runs through April 2003, after which the Seminole
contract for the same output begins in 2003. The second contract for the
remaining 25% of the output runs through May 2005 and can be extended by either
Florida Power and Light Company or Oleander for two years at predetermined
prices.
We have two remaining generating facilities under construction. We expect
our Holland Energy plant in Shelby Co., IL, a 665 MW gas combined cycle
facility, to be operational by the fall of 2002. We expect our High Desert plant
in Victorville, CA, a 750 MW gas combined cycle facility, to be operational in
2003.
Loss on Sale of Steam Turbine
- -----------------------------
In the fourth quarter of 2001, we recognized a $30 million impairment loss on
four turbines, associated with a discontinued development program as required by
SFAS No. 121, Accounting for the Impairment of Long-Lived Assets and for
Long-Lived Assets to be Disposed of. Since that time, many other companies have
canceled development projects and the market values for turbines have declined
significantly. Orders for three of the four turbines were canceled with
termination fees paid to the manufacturer consistent with the amount recognized
in December 2001. The fourth turbine-generator set was sold during the second
quarter of 2002 for a value $6.0 million below its book value.
Certain Relationships
- ---------------------
Michael J. Wallace, prior to becoming President of Constellation Generation
Group on January 1, 2002, was a Managing Member and Managing Director and
greater than 10% owner of Barrington Energy Partners, LLC. Upon becoming
President of Constellation Generation Group, Mr. Wallace terminated his
affiliation with Barrington, and no longer holds any ownership interest in it.
We paid Barrington Energy Partners approximately $2.1 million for consulting
services provided to Constellation Energy and its subsidiary, Constellation
Nuclear during the six months ended June 30, 2002.
George P. Stamas served as Secretary of the Company from May 1, 2002 until
August 12, 2002. Mr. Stamas is a senior partner at Kirkland and Ellis, who
continued to provide legal services to the Company during that period.
25
Strategy
- --------
On October 26, 2001, we announced the decision to remain a single company and
canceled prior plans to separate our merchant energy business from our other
businesses and terminated our power business services agreement with Goldman
Sachs.
Our primary growth strategy centers on our merchant energy business. The
strategy for our merchant energy business is to be a leading competitive
provider of energy solutions for wholesale customers in North America. Our
merchant energy business has electric generation assets located in various
regions of the United States and engages in power marketing and risk management
activities and provides energy solutions to meet wholesale customers' needs
throughout North America.
Our merchant energy business integrates electric generation assets with
power marketing and risk management of energy and energy-related commodities.
This integration allows our merchant energy business to maximize value across
energy products, over geographic regions, and over time. Our origination and
risk management operation adds value to our generation assets by providing
national market access, market infrastructure, real-time market intelligence,
risk management and arbitrage opportunities, and transmission and transportation
expertise. Generation capacity supports our origination and risk management
operation by providing a source of reliable power supply, enhancing our ability
to structure sophisticated products and services for customers, building
customer credibility, and providing a physical hedge.
Currently, our merchant energy business services approximately 14,000
megawatts of peak load. Our merchant energy business owns approximately 10,500
megawatts of generation capacity. We also have approximately 1,400 megawatts of
natural gas-fired combined cycle production facilities under construction in
California and Illinois.
To achieve our strategic objectives, we expect to continue to support our
origination and risk management operation with generation assets that have
diversified geographic, fuel, and dispatch characteristics. We also expect to
use a disciplined growth strategy through originating transactions with
wholesale customers and by acquiring and developing additional generating
facilities when desirable to support our origination and risk management
operation.
Our merchant energy business will focus on long-term, high-value sales of
energy, capacity, and related products to distribution companies and other
wholesale purchasers primarily in the regional markets in which end-user
electricity rates have been deregulated and thereby separated from the cost of
generation supply. These markets include the Northeast region, the Mid-Atlantic
region, Florida, California, and Texas. In addition, our merchant energy
business is focusing on providing energy supply and services to large commercial
and industrial customers in these deregulated regions.
The growth of BGE and our other retail energy services businesses is
expected through focused and disciplined expansion.
Customer choice, regulatory change, and energy market conditions
significantly impact our business. In response, we regularly evaluate our
strategies with these goals in mind: to improve our competitive position, to
anticipate and adapt to business environment and regulatory changes, and to
maintain a strong balance sheet and an investment-grade credit quality.
In the fourth quarter of 2001, we undertook a number of initiatives to
reduce our costs towards competitive levels and to ensure that our management
and capital resources are focused on our core energy businesses. This included
the implementation of workforce reduction programs, termination of all planned
development projects not currently under construction, and the acceleration of
our exit strategy for certain non-core assets.
We also might consider one or more of the following strategies:
o the complete or partial separation of BGE's transmission function from
its distribution function,
o mergers or acquisitions of utility or non-utility businesses or assets,
and
o sale of assets or one or more businesses.
26
Business Environment
- --------------------
With the shift toward customer choice, competition, and the growth of our
merchant energy business, various factors affect our financial results. We
discuss these various factors in the Forward Looking Statements section on page
51.
In this section, we discuss in more detail several issues that affect our
businesses.
General Industry
- ----------------
The utility industry and energy markets continue to experience significant
changes as a result of weaker and more volatile wholesale markets, liquidity
issues of various industry participants, lower short-term and long-term power
prices, and the slowing of the U.S. economy.
Due to market conditions in 2001, we canceled our separation plans and
terminated our power business services agreement with Goldman Sachs & Co.
(Goldman Sachs) on October 26, 2001 and decided to maintain our existing
corporate structure. We also terminated all planned development projects not
currently under construction. Separately, we initiated efforts to reduce costs
in order to become more competitive and to sell certain non-core assets to focus
management's attention and our capital resources on our core energy businesses.
During the second quarter of 2002, the energy markets were affected by
significant events, including expanded investigations by state and federal
authorities into business practices of energy companies in the deregulated power
and gas markets relating to "wash trading" to inflate revenues and volumes, and
other potential trading practices designed to manipulate market prices. In
addition, several merchant energy businesses significantly reduced their energy
trading activities due to deteriorating credit quality.
During the second quarter, several regional energy markets experienced a
significant decline in liquidity. As a result of the reduced market liquidity,
Constellation Power Source held energy positions in certain markets longer than
it otherwise would have. This caused Constellation Power Source's average
value-at-risk for the second quarter to increase to $26 million compared to $19
million in the first quarter of 2002. We discuss the value-at-risk calculation
in more detail in the Market Risk section of our 2001 Annual Report on Form
10-K.
In response to this reduced market liquidity, Constellation Power Source
reduced these positions during the end of the second quarter and the beginning
of the third quarter of 2002 and continues to modify its liquidity limits to
reflect the underlying liquidity of the various regional energy markets. As a
result of these actions, Constellation Power Source's value-at-risk was
approximately $5 million as of August 12, 2002.
As discussed above, certain companies in the energy industry have been
experiencing deteriorating credit quality. We continue to actively manage our
credit portfolio to attempt to reduce the impact of a potential counterparty
default. As of June 30, 2002, approximately 72% of our credit portfolio was
rated at least investment grade by the major rating agencies, with 1% rated
below investment grade and 27% not rated. Of the 27% not rated, 91% primarily
represents governmental entities, municipalities, cooperatives, or other load
serving entities that Constellation Power Source assesses are equivalent to
investment grade based on internal credit ratings.
We continue to examine plans to achieve our strategies and to further
strengthen our balance sheet and enhance our liquidity. We discuss our
strategies in the Strategy section on page 26. We discuss our liquidity in the
Financial Condition section on page 45.
Electric Competition
- --------------------
We are facing competition in the sale of electricity in wholesale power markets
and to retail customers.
Maryland
- --------
As a result of the deregulation of electric generation in Maryland, the
following occurred effective July 1, 2000:
o All customers can choose their electric energy supplier. BGE provides
standard offer service for customers that do not select an alternative
supplier at fixed rates over various time periods during the transition
period. 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 Commercial and industrial customers have up to four service options
that will fix electric energy rates and transition charges for a period
that ends in 2004 to 2006.
o BGE transferred, at book value, its nuclear generating assets, its
nuclear decommissioning trust fund, and related assets and liabilities to
Calvert Cliffs Nuclear Power Plant, Inc. In addition, BGE transferred, at
book value, its fossil generating assets and related assets and
liabilities and its partial ownership interest in two coal plants and a
hydroelectric plant located in Pennsylvania to Constellation Power Source
Generation.
Constellation Power Source provides BGE with 100% of the energy and capacity
required to meet its standard offer service obligations for the first three
years of the transition period. In August 2001, BGE entered into contracts with
Constellation Power Source to supply 90% and Allegheny Energy Supply Company,
LLC to supply the remaining 10% of
27
BGE's standard offer service for the final three years (July 1, 2003 to June 30,
2006) of the transition period. Over the transition period, the standard offer
service rate that BGE receives from its customers increases. This is offset by a
corresponding decrease in the competitive transition charge BGE receives.
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
- ------------
Several states, other than Maryland, have supported deregulation of the electric
industry. Other states that were considering deregulation have slowed their
plans or postponed consideration. While our merchant energy business may be
affected by the slow down in deregulation, the FERC initiatives regarding the
formation of larger Regional Transmission Organizations as discussed in the FERC
Regulation--Regional Transmission Organizations section on page 29 and its
proposal released in July 2002 on a standard market design could provide our
merchant energy business other opportunities.
We discuss our California Power Purchase Agreements with Pacific Gas &
Electric (PGE) and Southern California Edison (SCE) in more detail in our
Merchant Energy Business section on page 34. The situation with PGE and SCE has
not had a material impact on our financial results. However, we cannot provide
any assurance that the events in California will not have a material, adverse
impact on our financial results, or that any legislative, regulatory, or other
solution enacted in California will not have a negative effect on our business
opportunities in California.
As a result of ongoing litigation before the FERC regarding sales into the
spot markets of the California Independent System Operator (ISO) and Power
Exchange, we may be required to pay refunds of between $3 and $4 million for
transactions that we entered into with these entities for the period between
October 2000 and June 2001.
As part of the settlement agreement we signed with various California
entities in regard to our High Desert Power Project discussed in the Events of
2002 section on page 24, the California entities disclaimed any right they may
have to a refund. We do not know if we will still be required to pay any refunds
to the California entities party to the settlement agreement.
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.
Regulation by the Maryland PSC
- ------------------------------
In addition to electric restructuring which was discussed earlier, regulation by
the Maryland PSC influences BGE's businesses.
The Maryland PSC determines the rates that BGE can charge customers for
electric distribution and gas businesses. The Maryland PSC incorporates into
BGE's rates the transmission rates determined by FERC. Prior to July 1, 2000,
BGE's regulated electric rates consisted primarily of a "base rate" and a "fuel
rate." BGE unbundled its electric 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 and higher operating 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.
As a result of the Restructuring Order, BGE's residential electric base
rates are frozen until 2006. Electric delivery service rates are frozen until
2004 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
- ---------
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.
28
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 collected this accumulated difference from
customers over the twelve-month period ended October 2001. 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 and a current proceeding with the Maryland PSC in more detail in the Gas
Cost Adjustments section on page 42.
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).
On July 12, 2001, FERC provisionally granted RTO status to PJM and ordered
it to engage in mediation with the New York ISO and the New England ISO to
create a business plan to form one Northeast RTO, using PJM as a platform. After
further hearings by FERC, it announced that it is re-evaluating its Order
regarding a Northeast RTO. In the meantime, PJM is exploring opportunities to
expand into other regions. The PJM West region recently was formed and Virginia
Electric and Power Company is discussing with PJM the formation of a PJM South
region.
The creation of large RTOs could benefit our merchant energy business by
allowing easier access to transmission and a uniform rate across various
regions.
In addition, on July 1, 2002, PJM filed for an extension relating to the
implementation of a uniform transmission rate until at least January 1, 2005.
BGE filed in support of the PJM extension. A uniform rate could expose BGE to
higher transmission rates.
BGE, jointly with other PJM transmission owners, requested a rehearing and
clarification from FERC on its July 12, 2001 order regarding certain incentive
rates, interconnection procedures, and allocations of interconnection costs.
FERC has not yet issued an order on this request.
Cash Management
- ---------------
In August 2002, the FERC issued proposed rules for the regulation of cash
management practices of a regulated subsidiary of a nonregulated parent. As
currently proposed, we do not believe the proposed rule will have a material
effect on our, and BGE's, financial results. Please refer to the Notes to
Consolidated Financial Statements section on page 19 for a discussion of our
cash management arrangement.
Weather
- -------
Merchant Energy Business
- ------------------------
Weather conditions in the different regions of North America influence the
financial results of our merchant energy business. Weather conditions can affect
the supply of and demand for electricity and fuels, and changes in energy supply
and demand may impact the price of these energy commodities in both the spot
market and the forward market. Typically, demand for electricity and its price
are higher in the summer and the winter, when weather is more extreme.
Similarly, the demand for and price of natural gas and oil are higher in the
winter. However, all regions of North America typically do not experience
extreme weather conditions at the same time.
29
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
42.
We measure the weather's effect using "degree days." The measure of degree
days for a given 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 and cooling degree days in the quarters and
six months ended June 30, 2002 and 2001, and the percentage change in the number
of degree days between these periods in the following table:
Quarter Ended Six Months Ended
June 30 June 30
2002 2001 2002 2001
- ---------------------------------------------------------
Heating degree days 493 471 2,616 2,918
Percent change
from prior period 4.7% (10.3)%
Cooling degree days 295 262 298 262
Percent change
from prior period 12.6% 13.7%
Other Factors
- -------------
A number of other factors significantly influence the level and volatility of
prices for energy commodities and related derivative products for our merchant
energy business. These factors include:
o seasonal daily and hourly changes in demand,
o extreme peak demands,
o available supply resources,
o transportation availability and reliability within and between regions,
o procedures used to maintain the integrity of the physical electricity
system during extreme conditions, and
o changes in the nature and extent of federal and state regulations.
These other factors can affect energy commodity and derivative prices in
different ways and to different degrees. These effects may vary throughout the
country as a result of regional differences in:
o weather conditions,
o market liquidity,
o capability and reliability of the physical electricity and gas systems,
and
o the nature and extent of electricity deregulation.
Other factors, aside from weather, also 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 only customers 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.
30
Results of Operations for the Quarter and Six Months Ended June 30, 2002
- ------------------------------------------------------------------------
Compared with the Same Periods of 2001
- --------------------------------------
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 and income taxes are discussed in
the aggregate for all segments in the Consolidated Nonoperating Income and
Expenses section on page 44.
Overview
- --------
Net Income
- ----------
Quarter Ended Six Months Ended
June 30, June 30,
2002 2001 2002 2001
- ----------------------------------------------------------
(In millions)
Net Income Before Special
Items Included in
Operations:
Merchant energy $63.5 $52.4 $ 93.5 $ 94.8
Regulated electric 22.2 18.0 51.2 45.7
Regulated gas 2.9 3.0 30.7 31.7
Other nonregulated 2.7 (8.1) (4.1) (13.7)
- ----------------------------------------------------------
Net Income Before Special
Items Included in
Operations 91.3 65.3 171.3 158.5
Special Items Included in
Operations:
Gains on sale of
investments and
other assets 1.9 10.3 166.2 20.4
Workforce reduction
costs (8.0) -- (23.6) --
Loss on sale of turbine (3.9) -- (3.9) --
- ----------------------------------------------------------
Net Income Before
Cumulative Effect of
Change in Accounting
Principle 81.3 75.6 310.0 178.9
Cumulative Effect of
Change in Accounting
Principle -- -- -- 8.5
- ----------------------------------------------------------
Net Income $81.3 $75.6 $310.0 $187.4
==========================================================
Quarter Ended June 30, 2002
- ---------------------------
Our total net income for the quarter ended June 30, 2002 increased $5.7 million,
or $.04 per share, compared to the same period of 2001 mostly because of the
following:
o We had higher earnings from our origination and risk management
operation.
o We experienced warmer weather in the central Maryland region.
o The addition of Nine Mile Point Nuclear Station (Nine Mile Point) to
the generation fleet increased income due to the seasonality of the power
purchase agreement for this plant.
o We had cost reductions due to productivity initiatives associated with
our corporate-wide workforce reduction and other productivity programs.
o We had higher earnings from our other nonregulated businesses due to
the growth of our energy services business and improved results from our
international portfolio.
These increases were partially offset by the following:
o We had lower earnings due to the extended outage at Calvert Cliffs to
replace the steam generators at Unit 1.
o We recorded costs of $8.0 million after-tax, or $.05 per share,
associated with our corporate-wide workforce reduction programs.
o Our merchant energy business experienced higher coal costs and lower
energy prices in California.
o Our merchant energy business recorded a loss on the sale of a turbine of
$3.9 million after-tax, or $.02 per share.
o Our other nonregulated businesses had lower gains on the sale of
securities and other assets in 2002 compared to 2001.
Six Months Ended June 30, 2002
- ------------------------------
Our total net income for the six months ended June 30, 2002 increased $122.6
million, or $.70 per share, compared to the same period of 2001 mostly because
of the following:
o We recognized a $163.3 million after-tax gain, or $1.00 per share, on
the sale of our investment in Orion as previously discussed in the Events
of 2002 section on page 23.
o We had higher earnings from our origination and risk management
operation.
o We had cost reductions due to productivity initiatives associated with
our corporate-wide workforce reduction and other productivity programs.
31
o We had higher earnings from our other nonregulated businesses due to
the growth of our energy services business and improved results from our
international portfolio.
These increases were partially offset by the following:
o We had lower earnings due to the extended outage at Calvert Cliffs to
replace the steam generators at Unit 1.
o We recorded costs of $23.6 million after-tax, or $.15 per share,
associated with our corporate-wide workforce reduction programs.
o Our merchant energy business experienced lower energy prices in
California.
o Our merchant energy business recorded a loss on the sale of a turbine
of $3.9 million, or $.02 per share.
In addition, our other nonregulated businesses recorded the following in the
first six months of 2001 that had a positive impact in that period:
o 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, and
o gains on the sale of securities of $20.4 million after-tax, or $.13 per
share.
Earnings per share contributions from all of our business segments for the
six months ended June 30, 2002 are impacted by the dilution resulting from the
issuance of 13.2 million of common shares during 2001.
In the following sections, we discuss our net income by business segment in
greater detail.
Merchant Energy Business
- ------------------------
Our merchant energy business is exposed to various market risks as discussed
further in the General Industry section on page 27 and in Item 7. Management's
Discussion and Analysis - Market Risk section of our 2001 Annual Report on Form
10-K.
We record the financial impacts of these market risks in earnings in
different periods depending upon which portion of our merchant energy business
they affect.
o We record changes in the fair value of contracts in our origination and
risk management operation that are subject to mark-to-market accounting
in revenues on a net basis in the period in which the change occurs.
o We record revenues as they are earned and electric fuel and purchased
energy costs as they are incurred for contracts subject to accrual
accounting, including the load-serving activities in Texas and New
England as discussed further in the Physical Delivery Business section on
page 38.
o Prior to the settlement of the forecasted transaction being hedged, we
record changes in the fair value of contracts designated as cash-flow
hedges of our generation operations in other comprehensive income to the
extent that the hedges are effective. We record the effective portion of
the changes in fair value of hedges in earnings in the period the
settlement of the hedged transaction occurs. We record the ineffective
portion of the changes in fair value of hedges, if any, in earnings in
the period in which the change occurs.
Mark-to-market accounting requires us to make estimates and assumptions
using judgment in determining the fair value of our contracts and in recording
revenues from those contracts. We discuss the effects of mark-to-market
accounting on our revenues in the Origination and Risk Management Revenues
section on page 34. We discuss mark-to-market accounting and the accounting
policies for the merchant energy business further in the Application of Critical
Accounting Policies section on page 22 and in Note 1 of our 2001 Annual Report
on Form 10-K.
As discussed in the Business Environment -- Electric Competition section on
page 27, our 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 merchant energy business, and
Constellation Power Source began selling to BGE 100% of the energy and capacity
required to meet its standard offer service obligations for the first three
years (July 1, 2000 to June 30, 2003) of the transition period. In August 2001,
BGE entered into a contract with Constellation Power Source to provide 90% of
the energy and capacity required for BGE to meet its standard offer service
requirements for the final three years (July 1, 2003 to June 30, 2006) of the
transition period.
In addition, the merchant energy business revenues include 90% of the
competitive transition charges (CTC revenues) BGE collects from its customers
and the portion of BGE's revenues providing for nuclear decommissioning costs.
32
Net Income
Quarter Ended Six Months Ended
June 30, June 30,
2002 2001 2002 2001
- ---------------------------- ------- ------ --------- -------
(In millions)
Revenues $581.7 $384.0 $1,048.1 $729.7
Operating expenses 393.6 261.4 728.3 487.5
Workforce reduction costs 5.3 -- 10.3 --
Loss on sale of turbine 6.0 -- 6.0 --
Depreciation and
amortization 57.2 40.7 113.9 81.0
Taxes other than income
taxes 20.5 11.3 41.0 22.8
- ---------------------------- ------- ------ --------- -------
Income from Operations $ 99.1 $ 70.6 $ 148.6 $138.4
============================ ======= ====== ========= =======
Net Income $ 56.4 $ 52.4 $ 83.4 $ 94.8
============================ ======= ====== ========= =======
Net Income Before Special
Items Included in
Operations $63.5 $52.4 $93.5 $94.8
Workforce reduction
costs (3.2) -- (6.2) --
Loss on sale of turbine (3.9) -- (3.9) --
- ---------------------------- ------- ------ --------- -------
Net Income $56.4 $52.4 $83.4 $94.8
============================ ======= ====== ========= =======
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 13 provides a reconciliation
of operating results by segment to our Consolidated Financial Statements.
Revenues
- --------
Merchant energy revenues increased $197.7 million during the quarter and $318.4
million during the six months ended June 30, 2002 compared to the same periods
of 2001 mostly due to:
o higher revenues from other sales of generation from our new facilities
placed in service in mid-summer 2001 and during the second quarter of
2002, and Nine Mile Point,
o higher revenues from origination and risk management revenues recorded
on a mark-to-market basis, and
o the re-designation of our Texas load-serving business to non-trading as
discussed in more detail on page 38.
These increases were partially offset by a decrease in revenues related to
supplying BGE's standard offer service requirements and lower revenues from our
California power purchase agreements with PGE and SCE.
We discuss these revenue changes in more detail below.
Revenues from BGE Standard Offer Service
- ----------------------------------------
The revenues from BGE's Standard Offer Service requirements decreased by $12.1
million, including CTC revenues that decreased $2.4 million, during the quarter
ended June 30, 2002 compared to the same period of 2001.
The revenues from BGE's Standard Offer Service requirements decreased by
$22.3 million, including CTC revenues that decreased $7.0 million, during the
six months ended June 30, 2002 compared to the same period of 2001.
These decreases were due to approximately 1,200 megawatts of larger
commercial and industrial customers leaving BGE's standard offer service and
electing other electric generation suppliers. As a result, our merchant energy
business has an increasing amount of generating capacity that will be sold at
wholesale market rates and thus be subject to future changes in wholesale
electricity prices. In addition, the CTC rate our merchant energy business
receives from BGE customers declines over the transition period as previously
discussed in the Electric Competition - Maryland section on page 27.
Other Merchant Generation Revenues
- ----------------------------------
Excluding revenues from BGE's Standard Offer Service, merchant generation
revenues increased $170.4 million during the quarter and $254.5 million during
the six months ended June 30, 2002 compared to the same periods of 2001
primarily due to:
o revenues of $103.3 million for the quarter and $195.8 million for the
six months from Nine Mile Point that was acquired in November 2001,
o an increase of $74.8 million for the quarter and $98.2 million for the
six months related to the re-designation of the Texas load-serving
business to non-trading from mark-to-market energy revenues, and
o revenues of $14.1 million for the quarter and $17.5 million for the six
months from our new generating facilities that were placed in service
during mid-summer 2001 and the second quarter of 2002.
These increases were partially offset by $17.2 million during the quarter
and $38.6 million during the six months of lower sales of power from our
Baltimore plants in excess of that required to serve BGE's standard offer
service requirements compared to same periods of 2001. These lower sales were
due primarily to the extended outage at Calvert Cliffs in order to replace the
steam generators at Unit 1 and lower generation from our coal plants. In
addition, our generation operation had lower revenues from our California
projects as discussed on the next page, and in March 2001, our generation
operation recognized a $9.5 million gain on the sale of a project under
development in the PJM region that had a positive impact in that period.
33
California Power Purchase Agreements
- ------------------------------------
Our generation operation has $269.0 million invested in 13 operating power
projects of which our ownership percentage represents 137 megawatts of
electricity that are sold to PGE and SCE in California under power purchase
agreements.
Under these agreements, the projects supply electricity to these utilities
at variable rates. Revenues from these projects, net of credit reserves,
decreased $8.4 million during the quarter and $8.0 million for the six months
ended June 30, 2002 compared to the same periods of 2001. While California power
prices were significantly lower during the first half of 2002 compared to the
same period of 2001, first quarter results were offset by credit reserves
established for our exposure in California during the first quarter of 2001 that
had a negative impact in that period. These reserves were subsequently reversed
in the first quarter of 2002 as discussed below.
Our merchant energy business was not paid in full for its sales from these
plants to the two utilities from November 2000 through early April 2001. As of
June 30, 2002, we received $33 million of the $45 million for unpaid power sales
plus interest, which included payment of 100% of the SCE outstanding balance. We
expect to collect the remaining outstanding balance plus interest from PGE
within the next several months. Accordingly, we reversed all of our credit
reserves that totaled $9.1 million during the first quarter of 2002.
The projects entered into agreements with PGE through July 2006 and SCE
through April 2007 that provide for fixed-price payments averaging $53.70 per
megawatt-hour plus the stated capacity payments in the original agreements.
Origination and Risk Management Revenues
- ----------------------------------------
Revenues include net gains and losses from Constellation Power Source
origination and risk management activities for which we use the mark-to-market
method of accounting. We discuss the mark-to-market method of accounting and
Constellation Power Source's activities in more detail in the Application of
Critical Accounting Policies section on page 22 and in Note 1 in our 2001 Annual
Report on Form 10-K.
As a result of the nature of its operations and the use of mark-to-market
accounting for certain activities, Constellation Power Source's revenues and
earnings will fluctuate. We cannot predict these fluctuations, but the impact on
our revenues and earnings could be material. We discuss our market risk in more
detail in Item 7. Management's Discussion and Analysis - Market Risk section in
our 2001 Annual Report on Form 10-K. The primary factors that cause fluctuations
in our revenues and earnings are:
o the number, size, and profitability of new transactions,
o changes in the level and volatility of forward commodity prices and
interest rates,
o changes in estimates of customers' load requirements as a result of
changes in weather and customer attrition due to the selection of other
suppliers, and
o the number and size of our open commodity and derivative positions.
Origination and risk management revenues were as follows:
Quarter Ended Six Months Ended
June 30, June 30,
2002 2001 2002 2001
- ---------------------------- -------- ------- ------ -------
(In millions)
Origination transactions $85.4 $65.6 $ 94.9 $103.5
Risk management activities
Realized (13.7) (16.6) 7.2 (47.2)
Unrealized 18.6 (2.0) 52.0 2.7
- ---------------------------- -------- ------- ------ -------
Total risk management
activities 4.9 (18.6) 59.2 (44.5)
- ---------------------------- -------- ------- ------ -------
Total $90.3 $47.0 $154.1 $ 59.0
============================ ======== ======= ====== =======
Revenues from origination transactions represent the initial unrealized fair
value of new wholesale energy transactions at the time of contract execution.
Risk management revenues represent both realized and unrealized gains and losses
from changes in the value of our entire portfolio. We discuss the changes in
origination and risk management revenues below.
Constellation Power Source's origination and risk management revenues are
influenced by our focus on serving the full electric energy and capacity
requirements of electric utility customers. Providing utilities' full energy and
capacity requirements requires greater ownership of, or contractual access to,
power generating facilities, as opposed to merely standard products obtainable
in liquid trading markets.
The relationship of the realized portion of revenue to total origination and
risk management revenue in the table above reflects the nature of the
origination transactions which Constellation Power Source has executed. A
significant portion of these contracts provide for Constellation Power Source to
serve customers' energy requirements at fixed prices that are lower in the early
years of the contracts but that are expected to provide increased margins and
cash flows over the remaining terms of the contracts. We discuss the settlement
terms of our contracts on page 36.
Origination and risk management revenues increased $43.3 million during the
quarter ended June 30, 2002 compared to the same period of 2001 because of net
gains from risk management activities and increased revenues from origination
transactions. The increase in net gains from risk management activities is
primarily due to favorable changes in regional power prices, price volatility,
and other factors in the second quarter of 2002 compared to
34
the same period of 2001. The increase in origination revenue reflects higher
margins on individually significant transactions in 2002 as compared to the same
period of 2001.
Origination and risk management revenues increased $95.1 million during the
six months ended June 30, 2002 compared to the same period of 2001 mostly
because of net gains from risk management activities partially offset by lower
revenues from origination transactions. The increase in net gains from risk
management activities is primarily due to favorable changes in regional power
prices, price volatility, and other factors in 2002 compared to the same period
of 2001. The decreases in origination revenue reflect fewer individually
significant transactions in 2002 as compared to the same period of 2001.
Constellation Power Source's mark-to-market energy assets and liabilities are
comprised of a combination of derivative and non-derivative (physical)
contracts. While some of these contracts represent commodities or instruments
for which prices are available from external sources, other commodities and
certain contracts are not actively traded and are valued using other pricing
sources and modeling techniques to determine expected future market prices,
estimated quantities, or both. We discuss our modeling techniques on page 37.
Mark-to-market energy assets and liabilities consisted of the following:
June 30, December 31,
2002 2001
- ----------------------------------------------------------
(In millions)
Current Assets $ 403.0 $ 398.4
Noncurrent Assets 1,184.4 1,819.8
- ----------------------------------------------------------
Total Assets 1,587.4 2,218.2
- ----------------------------------------------------------
Current Liabilities 275.9 323.3
Noncurrent Liabilities 802.5 1,476.5
- ----------------------------------------------------------
Total Liabilities 1,078.4 1,799.8
- ----------------------------------------------------------
Net mark-to-market energy asset $ 509.0 $ 418.4
==========================================================
The primary components of our net mark-to-market energy asset are the following
as of June 30, 2002:
(In millions)
New England load-serving $253
PJM generation hedge 118
Other positions 138
- -------------------------------------------
Total $509
===========================================
The New England load-serving portion of the net asset primarily represents
the fair value of contracts to serve customers' full energy requirements and
related energy supply resources.
The PJM generation hedge is comprised of a group of options that serve as an
economic hedge of the PJM generation portfolio. These options give us the right
to sell power at a floor price which is valuable to our generation operation
when market prices are low and also give us the right to buy power at a capped
price, which adds value when market prices are high.
A significant portion of the remaining $138 million relates to power sales
transactions in California that are fully hedged.
The following are the primary sources of the change in the net
mark-to-market energy asset during quarter ended June 30, 2002 and the six
months ended June 30, 2002:
Change in Net Mark-to-Market Energy Asset
Quarter Ended Six Months Ended
June 30, 2002 June 30, 2002
- --------------------------------------------------------------------
(In millions)
Fair value beginning of period $365.1 $418.4
Changes in fair value recorded as
revenues
Origination transactions $85.4 $94.9
------ ------
Unrealized risk management
revenues:
Contracts settled 13.7 (7.2)
Changes in valuation
techniques 3.8 4.3
Unrealized changes in fair
value 1.1 54.9
------ ------
Total unrealized risk
management revenues $18.6 $52.0
------ ------
Total changes in fair value
recorded as revenues 104.0 146.9
Changes in fair value recorded as
operating expenses 2.7 3.0
Net change in premiums on options 26.5 (10.6)
Texas contracts re-designated
as non-trading -- (63.3)
Other changes in fair value 10.7 14.6
- ------------------------------------------------------------------
Fair value at June 30, 2002 $509.0 $509.0
==================================================================
Origination transactions represent the initial unrealized fair value at the
time these contracts are executed. Changes in valuation techniques represent
improvements in estimation techniques, including modeling and other statistical
enhancements used to value our portfolio to reflect more accurately the economic
value of our contracts. Unrealized changes in fair value represent the change in
value of our unrealized net mark-to-market energy asset due to changes in
commodity prices, the volatility of options on commodities, the time value of
options, and net changes in other valuation adjustments. Changes in fair value
recorded as operating expenses represent accruals for future incremental
expenses in connection with servicing origination transactions. While these
accruals are recorded as part of the fair value of the net mark-to-market energy
asset, they are reflected in the income statement as expenses rather than
revenue.
We record premiums on options purchased as an increase in the net
mark-to-market energy asset and premiums on options sold as a decrease in the
net mark-to-market energy asset. Prior to 2001, we had entered into purchased
option and energy tolling contracts in connection with serving our energy sales
contracts. The option and tolling contracts, by their nature, exposed us to
changes in
35
the volatility of energy prices. During the second quarter of 2002, we purchased
options as part of our overall risk management strategy that resulted in a
higher net mark-to-market energy asset. However, the net change in premiums on
options for the six months ended June 30, 2002 reflects a net increase in
options sold that reduced our exposure to option volatility.
We discuss our re-designation of the Texas load-serving activities as
non-trading in more detail on page 38. The settlement term of the net
mark-to-market energy asset and sources of fair value as of June 30, 2002 are as
follows:
Settlement Term
-----------------------------------------------------------------------------------------------
Total
2008 Fair
2002 2003 2004 2005 2006 2007 -2009 Thereafter Value
--------------------- ---------- -------- --------- ---------- --------- ---------- ---------- ----------- ----------
(In millions)
Prices provided by
external sources $106.7 $56.4 $(19.6) $(35.7) $13.6 $(2.9) $ 0.9 $ 4.2 $123.6
Prices based on
models (32.7) (13.7) 109.7 81.7 64.2 57.0 124.9 (5.7) 385.4
--------------------- ---------- -------- --------- ---------- --------- ---------- ---------- ----------- ----------
Total net
mark-to-market
energy asset $ 74.0 $42.7 $ 90.1 $ 46.0 $77.8 $54.1 $125.8 $(1.5) $509.0
===================== ========== ======== ========= ========== ========= ========== ========== =========== ==========
The portion of the net mark-to-market energy asset as of June 30, 2002 that
was valued using prices provided by external sources decreased compared to the
level that was similarly valued as of December 31, 2001. Two primary factors
contributed to the decrease:
o the re-designation of our Texas load-serving business as non-trading as
described on page 38, which resulted in a reduction of the net
mark-to-market energy asset, most of which was valued using prices
available from external sources, and
o a reduction in the portion of our New England load-serving business for
which prices are available from external sources due to a significant
decrease in market liquidity and available pricing information in New
England as a result of pending market changes.
Pending changes in the New England market and general market conditions have
reduced market liquidity and pricing information compared to the information
that was available as of December 31, 2001. Because of the long-term nature of
our load-serving contracts and supply arrangements and changes in this market, a
greater proportion of these contracts extend for terms for which market prices
are not presently available from external sources. We discuss the New England
load-serving business in more detail on page 38.
The following table presents the settlement terms of our net mark-to-market
energy asset excluding contracts associated with the New England load-serving
business.
Settlement Term Excluding New England Load-Serving Business
---------------------------------------------------------------------------------------------
Total
2008 Fair
2002 2003 2004 2005 2006 2007 -2009 Thereafter Value
--------------------- ---------- -------- --------- --------- -------- ---------- ---------- ----------- ----------
(In millions)
Prices provided by
external sources $91.1 $56.9 $19.9 $(13.5) $25.8 $(3.2) $ -- $ -- $177.0
Prices based on
models 0.3 4.8 (0.7) 11.1 21.1 24.1 18.2 0.1 79.0
--------------------- ---------- -------- --------- --------- -------- ---------- ---------- ----------- ----------
Total $91.4 $61.7 $19.2 $ (2.4) $46.9 $20.9 $18.2 $0.1 $256.0
===================== ========== ======== ========= ========= ======== ========== ========== =========== ==========
Constellation Power Source manages its risk on a portfolio basis based upon
the delivery period of its contracts and the individual components of the risks
within each contract. Accordingly, we record and manage the energy purchase and
sale obligations under our contracts in separate components based upon the
commodity (e.g., electricity or gas), the product (e.g., electricity for
delivery during peak or off-peak hours), the delivery location (e.g., by
region), the risk profile (e.g., forward or option), and the delivery period
(e.g., by month and year).
Consistent with our risk management practices, we have presented the
information in the tables on the previous page based upon the ability to obtain
36
reliable prices for components of the risks in our contracts from external
sources rather than on a contract-by-contract basis. Thus, the portion of
long-term contracts that is valued using external price sources is classified in
the same caption as other shorter-term transactions that settle in the same
period. This presentation is consistent with how we manage our risk, and we
believe it provides the best indication of the basis for the valuation of our
portfolio. Since we manage our risk on a portfolio basis rather than
contract-by-contract, it is not practicable to determine separately the portion
of long-term contracts that is included in each valuation category. We describe
the commodities, products, and delivery periods included in each valuation
category in detail below.
The amounts for which fair value is determined using prices provided by
external sources represent the portion of forward, swap, and option contracts
for which price quotations are available through brokers or over-the-counter
transactions. The term for which such price information is available varies by
commodity, region, and product. The fair values included in this category are
the following portions of our contracts:
o forward purchases and sales of electricity during peak hours for delivery
terms through 2007, depending upon the region,
o forward purchases and sales of electricity during off-peak hours for
delivery terms through 2007, depending upon the region,
o options for the purchase and sale of electricity during peak hours for
delivery terms through 2003, depending upon the region,
o forward purchases and sales of electric capacity for delivery terms
through 2003, depending upon the region,
o forward purchases and sales of natural gas and oil for delivery terms
through 2006, and
o options for the purchase and sale of natural gas and oil for delivery
terms through 2006.
The remainder of the net mark-to-market energy asset is valued using models.
The portion of contracts for which such techniques are used includes standard
products for which external prices are not available and customized products
which are valued using modeling techniques to determine expected future market
prices, contract quantities, or both.
Modeling techniques include estimating the present value of cash flows based
upon underlying contractual terms and incorporate, where appropriate, option
pricing models and statistical and simulation procedures. Inputs to the models
include:
o observable market prices,
o estimated market prices in the absence of quoted market prices,
o the risk-free market discount rate,
o volatility factors,
o estimated correlation of energy commodity prices,
o estimated volumes for customer requirements, which are influenced by
customer switching behavior, impact of temperature on electric prices,
and customer acquisition and servicing costs,
o estimated volumes for tolling arrangements, and
o expected generation profiles of specific regions.
Additionally, we incorporate counterparty-specific credit quality and
factors for market price and volatility uncertainty and other risks in our
valuation. The inputs and factors used to determine fair value reflect
management's best estimates.
The electricity, fuel, and other energy contracts held by Constellation
Power Source have varying terms to maturity, ranging from contracts for delivery
the next hour to contracts with terms of ten years or more. Because an active,
liquid electricity futures market comparable to that for other commodities has
not developed, the majority of contracts used in the origination and risk
management operation are direct contracts between market participants and are
not exchange-traded or financially settling contracts that readily can be
liquidated in their entirety through an exchange or other market mechanism.
Consequently, Constellation Power Source and other market participants generally
realize the value of these contracts as cash flows become due or payable under
the terms of the contracts rather than through selling or liquidating the
contracts themselves.
Consistent with our risk management practices, the amounts shown in the
tables on the previous page as being valued using prices from external sources
include the portion of long-term contracts for which we can obtain reliable
prices from external sources. The remaining portions of these long-term
contracts are shown in the tables as being valued using models. In order to
realize the entire value of a long-term contract in a single transaction, we
would need to sell or assign the entire contract. If we were to sell or assign
any of our long-term contracts in their entirety, we may not realize the entire
value reflected in the tables. However, based upon the nature of the origination
and risk management operation, we expect to realize the value of these
contracts, as well as any contracts we may enter into in the future to manage
our risk, over time as the contracts and related hedges settle in accordance
with their terms. We do not expect to realize the value of these contracts and
related hedges by selling or assigning the contracts themselves in total.
The fair values in the tables represent expected future cash flows based on
the level of forward prices and volatility factors as of June 30, 2002. These
amounts do not represent the contractual maturities
37
and could change significantly as a result of future changes in these factors.
Additionally, because the depth and liquidity of the power markets varies
substantially between regions and time periods, the prices used to determine
fair value could be affected significantly by the volume of transactions
executed.
Constellation Power Source's management uses its best estimates to
determine the fair value of commodity and derivative contracts 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 mark-to-market energy assets and liabilities, and such
variations could be material.
Physical Delivery Business
- --------------------------
As a result of the changes in our organization and senior management in late
2001, including the cancellation of business separation and the termination of
the power business services agreement with Goldman Sachs, we re-evaluated our
load-serving activities in Texas and New England. We determined that since we
manage these activities as a physical delivery business rather than a trading
business, it is appropriate to apply accrual accounting for these activities.
Earnings initially will be lower because we will record the margin on new
transactions as power is delivered to customers over the contract term rather
than in full at the inception of each new contract. Additionally, we also expect
lower earnings volatility for this portion of our business because unrealized
changes in the fair value of load-serving contracts will no longer be recorded
as revenue at the time of the change under mark-to-market accounting as is
required for trading activities under EITF 98-10.
Re-designation of Texas Business
- --------------------------------
During February 2002, we re-designated our Texas load-serving business from
trading to non-trading (accrual accounting) under EITF 98-10. In Texas, we serve
our customers' energy requirements using physically delivering power purchase
agreements and our Rio Nogales plant. Further, changes in the Texas market in
mid-February 2002 significantly reduced trading activity and the ability to
manage load-serving transactions through trading activities.
Based upon these factors, we began to manage our Texas load-serving
activities as a physical delivery business separate from our trading activities
and re-designated this operation as non-trading effective February 15, 2002. We
believe that this designation more accurately reflects the substance of our
Texas load-serving physical delivery activities.
At the time of this change in designation, we reclassified the fair value of
load-serving contracts and physically delivering power purchase agreements in
Texas from "Mark-to-market energy assets and liabilities" to "Other assets" and
"Other deferred credits and other liabilities." The contracts reclassified
consisted of gross assets of $78 million and gross liabilities of $15 million,
or a net asset of $63 million.
Beginning February 15, 2002, the results of our Texas load-serving business
are included in "Nonregulated revenues" on a gross basis as power is delivered
to our customers. These revenues totaled $23.4 million for the period February
15, 2002 through March 31, 2002 and $98.2 million for the period February 15,
2002 through June 30, 2002. Prior to the date of re-designation, the results of
these activities were reported on a net basis as part of mark-to-market energy
revenues included in "Nonregulated revenues." Origination and risk management
revenues for the Texas trading activities were a net loss of $1.2 million for
the portion of the first quarter of 2002 prior to the designation as non-trading
and a net gain of $10.8 million for the second quarter of 2001 and a net loss of
$8.2 million for the six months ended June 30, 2001.
The change in designation of our Texas load-serving business will not impact
our cash flows. However, because future power sales revenues and costs from this
business will be reflected in our Consolidated Statements of Income as part of
"Nonregulated revenues" when power is delivered and "Operating expenses" when
the costs are incurred, this re-designation generally will delay the recognition
of earnings from this business in the future compared to what we would have
recognized under mark-to-market accounting.
New England Load-Serving Business
- ---------------------------------
The New England load-serving business consists primarily of contracts to serve
the full energy and capacity requirements of electric distribution utilities and
associated power purchase agreements to supply our customers' requirements. We
manage this business primarily to assure profitable delivery of customers'
energy requirements rather than as a traditional trading activity. Because EITF
98-10 significantly limits the circumstances under which contracts previously
designated as a trading activity may be re-designated as non-trading, we
presently must continue to include contracts entered into prior to the second
quarter of 2002 in our trading activities portfolio that is subject to
mark-to-market accounting under EITF 98-10. However, we use accrual accounting
for New England load-serving transactions and associated power purchase
agreements entered into beginning in the second quarter of 2002.
38
Operating Expenses
- ------------------
Merchant energy operating expenses increased $132.2 million during the quarter
and $240.8 million for the six months ended June 30, 2002 compared to the same
periods of 2001 mostly because of the following:
o Operations and maintenance costs increased $51.3 million for the quarter
and $109.3 million for the six months. These increases reflect the
operations of the new generating facilities and Nine Mile Point. These
increases were partially offset by cost reductions due to productivity
initiatives associated with our corporate-wide workforce reduction.
o Fuel and purchased energy costs increased $13.1 million for the quarter
and $14.6 million for the six months. These increases reflect the
operations of the new generating facilities and Nine Mile Point, an
increase in purchased energy to supply BGE Standard Offer Service due to
the extended outage at Calvert Cliffs, and higher coal prices. These were
partially offset by lower generation at our coal plants. We continue to
expect to incur additional costs in the future to operate our coal
generating facilities due to higher coal prices.
o Increases of $77.3 million for the quarter and $102.0 million for the
six months related to the re-designation of the Texas load-serving
business to non-trading from energy revenues that are mark-to-market.
o Origination and risk management operating expenses increased $7.0
million for the quarter and $36.6 for the six months as a result of the
growth of this operation.
These increased costs were partially offset by the absence of fees paid to
Goldman Sachs due to the termination of the power business services agreement in
October 2001. The Goldman Sachs fees were $5.0 million in the second quarter of
2001 and $11.5 million for the six months of 2001.
As a result of the events of September 11, 2001, the Nuclear Regulatory
Commission (NRC) issued regulations that require U.S. nuclear power plants to
provide for additional security measures. In order to fully comply with these
regulations, we expect to incur additional operating expenses, as well as, costs
for capital improvements at each of our two nuclear power plant sites, Calvert
Cliffs and Nine Mile Point. Our nuclear plants are taking all appropriate steps
to ensure compliance with these regulations.
Extended Nuclear Outages
- ------------------------
Our merchant energy business began an extended outage at Unit 1 of Calvert
Cliffs during the first quarter of 2002 to replace the steam generators. Our
merchant energy business completed the extended outage at the end of June 2002.
As previously discussed in this section, our merchant energy business had lower
revenues and higher operating costs due to the extended outage at Calvert
Cliffs. Calvert Cliffs will replace the steam generators for Unit 2 during the
2003 refueling outage. As a result of the extended outages, we expect lower
annual revenues and higher annual operating costs for each extended outage.
Workforce Reduction Costs
- -------------------------
As previously discussed in the Events of 2002 section on page 23, our merchant
energy business recognized expenses of $5.3 million pre-tax, or $3.2 million
after-tax, during the quarter and $10.3 million pre-tax, or $6.2 million
after-tax, for the six months associated with our workforce reduction efforts.
Once our workforce reduction efforts to date have been fully implemented,
our merchant energy business expects ongoing, full year cost savings of
approximately $24 million. These savings will be realized in either labor
included in operating expenses or capitalized labor, partially offset by other
increases in operating or capital costs.
Loss on Sale of Steam Turbine
- -----------------------------
As discussed in the Events of 2002 section on page 25, we recognized a $6.0
million pre-tax, or $3.9 million after-tax, impairment loss on the sale of a
steam turbine generator set during the second quarter of 2002.
Depreciation and Amortization Expense
- -------------------------------------
Merchant energy depreciation and amortization expense increased $16.5 million
during the quarter and $32.9 million for the six months ended June 30, 2002
compared to the same periods of 2001 mostly because of the depreciation and
amortization associated with the new generating facilities and Nine Mile Point.
Taxes Other than Income Taxes
- -----------------------------
Merchant energy taxes other than income taxes increased $9.2 million during the
quarter and $18.2 million for the six months ended June 30, 2002 as compared to
the same periods of 2001 mostly because of taxes other than income taxes
associated with Nine Mile Point.
39
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 merchant energy business on that date.
Effective July 1, 2000, BGE 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 merchant energy business.
As part of the Restructuring Order, the rates received from customers under
the standard offer service increase over the transition period as discussed
further in the Business Environment--Electric Competition section beginning on
page 27.
Net Income
- ----------
Quarter Ended Six Months Ended
June 30, June 30,
2002 2001 2002 2001
- -------------------------------------------------------------
(In millions)
Revenues $480.4 $497.5 $940.8 $989.8
Electric fuel and
purchased energy 273.8 293.9 514.3 559.7
Operations and maintenance 59.5 62.9 120.3 124.7
Workforce reduction costs 7.9 -- 28.8 --
Depreciation and
amortization 44.0 43.3 87.8 86.7
Taxes other than income
taxes 34.2 35.0 68.9 70.9
- -------------------------------------------------------------
Income from Operations $ 61.0 $ 62.4 $120.7 $147.8
=============================================================
Net Income $ 17.4 $ 18.0 $ 33.8 $ 45.7
=============================================================
Net Income Before Special
Items Included in
Operations $22.2 $18.0 $51.2 $45.7
Workforce reduction
costs (4.8) -- (17.4) --
- -------------------------------------------------------------
Net Income $17.4 $18.0 $33.8 $45.7
=============================================================
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 13 provides a reconciliation
of operating results by segment to our Consolidated Financial Statements.
Electric Revenues
- -----------------
The changes in electric revenues in 2002 compared to 2001 were caused by:
Quarter Ended Six Months Ended
June 30, June 30,
2002 vs. 2001 2002 vs. 2001
- -----------------------------------------------------------
(In millions)
Distribution sales
volumes $ 2.5 $ (1.8)
Standard Offer Service (7.7) (17.2)
Fuel rate surcharge (12.5) (27.3)
- -----------------------------------------------------------
Total change in electric
revenues from electric
system sales (17.7) (46.3)
Other 0.6 (2.7)
- -----------------------------------------------------------
Total change in
electric revenues $(17.1) $(49.0)
===========================================================
Distribution Sales Volumes
- --------------------------
"Distribution sales volumes" are sales to customers in our service territory at
rates set by the Maryland PSC.
The percentage changes in our distribution sales volumes,
by type of customer, in 2002 compared to 2001 were:
Quarter Ended Six Months Ended
June 30, June 30,
2002 vs. 2001 2002 vs. 2001
- -------------------------------------------------------
Residential 6.0% (0.8)%
Commercial (1.2) (0.5)
Industrial (1.0) (1.0)
During the quarter ended June 30, 2002, we distributed more electricity to
residential customers compared to the same period of 2001 due to warmer weather.
We distributed less electricity to commercial and industrial customers due to
decreased usage. During the six months ended June 30, 2002 we distributed about
the same amount of electricity to all customers.
Standard Offer Service
- ----------------------
As part of the Restructuring Order, BGE provides Standard Offer Service for
customers that do not select an alternative generation supplier as previously
discussed.
Standard Offer Service revenues decreased for the quarter ended June 30,
2002 compared to the same period of 2001 primarily as a result of large
commercial and industrial customers leaving BGE's Standard Offer Service and
electing other electric generation suppliers. These decreased revenues were
partially offset by an increase in the Standard Offer Service rate that BGE
charges its customers.
Standard Offer Service revenues decreased for the six months ended June 30,
2002 compared to the same period of 2001 primarily as a result of large
commercial and industrial customers leaving BGE's Standard Offer Service and
electing other electric generation suppliers and lower revenues due to
40
milder winter weather. These decreased revenues were partially offset by an
increase in the Standard Offer Service rate that BGE charges its customers.
As a result of large commercial and industrial customers leaving BGE's
service, BGE also had lower purchased energy expense as discussed in the
Electric Fuel and Purchased Energy Expenses section below.
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 below.
Electric Fuel and Purchased Energy Expenses
- -------------------------------------------
Quarter Ended Six Months Ended
June 30, June 30,
2002 2001 2002 2001
- --------------------------------------------------------
(In millions)
Actual costs $273.8 $281.6 $514.3 $532.9
Net recovery of
costs under
electric fuel
rate clause -- 12.3 -- 26.8
- --------------------------------------------------------
Total electric
fuel and
purchased
energy expenses $273.8 $293.9 $514.3 $559.7
========================================================
Actual Costs
- ------------
As discussed in the Business Environment--Electric Competition section on page
27, 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 merchant energy business.
Our actual costs of fuel and purchased energy for the quarter and six months
ended June 30, 2002 were lower compared to the same periods of 2001 mostly
because BGE purchased less energy due to larger commercial and industrial
customers leaving BGE's standard offer service and electing other electric
generation suppliers.
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 collected this accumulated
difference from customers over the twelve-month period ending October 2001.
Electric Operations and Maintenance Expenses
- --------------------------------------------
Regulated other electric operations and maintenance expenses decreased $3.4
million for the quarter and $4.4 million for the six months ended June 30, 2002
compared to the same periods of 2001 primarily as a result of cost reductions
due to productivity initiatives associated with our corporate wide workforce
reduction and other productivity initiative programs.
Workforce Reduction Costs
- -------------------------
As previously discussed in the Events of 2002 section on page 23, BGE's electric
business recognized expenses of $7.9 million pre-tax, or $4.8 million after-tax,
during the quarter and $28.8 million pre-tax, or $17.4 million after-tax, for
the six months associated with our workforce reduction efforts.
Once our workforce reduction efforts to date have been fully implemented,
BGE's electric business expects ongoing, full year cost savings of approximately
$33 million. These savings will be realized in either labor included in
operating expenses or capitalized labor, partially offset by other increases in
operating or capital costs.
Other Electric Operating Expenses
- ---------------------------------
Regulated other electric operating expenses were about the same for the quarter
and six months ended June 30, 2002 compared to the same periods of 2001.
41
Regulated Gas Business
- ----------------------
Net Income
- ----------
Quarter Ended Six Months Ended
June 30, June 30,
2002 2001 2002 2001
- -------------------------------------------------------------
(In millions)
Gas revenues $92.5 $109.6 $315.9 $467.3
Gas purchased for resale 38.7 52.2 163.0 305.1
Operations and maintenance 22.1 24.6 45.9 49.2
Depreciation and
amortization 11.8 12.2 24.5 26.5
Taxes other than income
taxes 7.8 8.3 17.2 18.4
- -------------------------------------------------------------
Income from operations $12.1 $ 12.3 $ 65.3 $ 68.1
=============================================================
Net income $ 2.9 $ 3.0 $ 30.7 $ 31.7
=============================================================
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 13 provides a reconciliation
of operating results by segment to our Consolidated Financial Statements.
Net income from the regulated gas business was about the same during the quarter
ended June 30, 2002 compared to the same period of 2001. Net income from the
regulated gas business decreased during the six months ended June 30, 2002
compared to the same period of 2001 mostly due to a decrease in earnings from
the sharing mechanism under our gas cost adjustment clauses.
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 2002 compared to 2001 were caused by:
Quarter Ended Six Months Ended
June 30, June 30,
2002 vs. 2001 2002 vs. 2001
- ---------------------------------------------------------
(In millions)
Distribution volumes $ (1.7) $ (13.0)
Base rates (0.5) (2.3)
Weather normalization 1.1 9.9
Gas cost adjustments (11.9) (101.1)
- ---------------------------------------------------------
Total change in gas
revenues from gas system
sales (13.0) (106.5)
Off-system sales (2.7) (42.5)
Other (1.4) (2.4)
- ---------------------------------------------------------
Total change in gas revenues $(17.1) $(151.4)
=========================================================
Distribution Volumes
- --------------------
The percentage changes in our gas distribution volumes, by type of customer, in
2002 compared to 2001 were:
Quarter Ended Six Months Ended
June 30, June 30,
2002 vs. 2001 2002 vs. 2001
- ----------------------------------------------------------
Residential (7.4)% (11.8)%
Commercial (3.6) 1.2
Industrial (10.0) (5.4)
During the quarter ended June 30, 2002, we distributed less gas to
residential customers compared to the same period of 2001 mostly due to lower
usage per customer partially offset by cooler weather in early spring. We
distributed less gas to commercial customers mostly due to lower usage per
customer. We distributed less gas to industrial customers mostly because of
lower usage by industrial customers due to their lower business needs related to
the general downturn in the economy and a decreased number of customers.
During the six months ended June 30, 2002, we distributed less gas to
residential customers compared to the same period of 2001 mostly due to milder
winter weather and lower usage per customer partially offset by an increased
number of customers. We distributed more gas to commercial customers mostly due
to higher usage per customer and an increased number of customers. We
distributed less gas to industrial customers mostly because of lower usage by
industrial customers due to their lower business needs related to the general
downturn in the economy and a decreased number of customers.
Base Rates
- ----------
Base rate revenues decreased for the quarter and six months ended June 30, 2002
compared to the same periods of 2001 mostly because of a decrease in the rate
approved by the Maryland PSC associated with the energy conservation surcharge
program.
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
2001 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. The shareholders' portion
decreased $0.3 million during the quarter and $2.1
42
million during the six months ended June 30, 2002 compared to the same periods
of 2001.
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
distributed and are included in gas distribution sales volumes.
During the quarter and six months ended June 30, 2002, gas cost adjustment
revenues decreased compared to the same periods of 2001 mostly because we
distributed less gas at a lower price.
In our annual gas adjustment clause review proceeding with the Maryland PSC,
our gas business is seeking recovery of a previously established regulatory
asset of $9.4 million for certain credits that were over-refunded to customers
through our market-based rates. Certain parties to the proceeding are
petitioning that our gas business should not be allowed to recover these costs.
We expect the Maryland PSC to issue an order during the fourth quarter of 2002.
Under SFAS No. 71, Accounting for the Effects of Certain Types of Regulation, we
would be required to write-off the amount, if any, that the Maryland PSC
disallowed. As of the date of this report, we cannot determine the outcome of
this review by the Maryland PSC.
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, 2002, revenues from off-system gas sales
decreased mostly because the gas we sold was at a lower price partially offset
by more gas sold as compared to the same period of 2001. During the six months
ended June 30, 2002, revenues from off-system gas sales decreased compared to
the same period of 2001 mostly because we sold less gas off-system at a lower
price.
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 and six months ended June 30, 2002, gas costs decreased
compared to the same periods of 2001 because we bought less gas at a lower
price.
Other Gas Operating Expenses
- ----------------------------
During the quarter and six months ended June 30, 2002, other gas operating
expenses decreased compared to the same periods of 2001 mostly because of cost
reductions associated with our corporate-wide workforce reduction and other
productivity initiative programs and lower depreciation and amortization
expense.
Once our workforce reduction efforts to date have been fully implemented,
BGE's gas business expects ongoing, full year cost savings of approximately $15
million. These savings will be realized in either labor included in operating
expenses or capitalized labor, partially offset by other increases in
operating or capital costs.
43
Other Nonregulated Businesses
- -----------------------------
Net Income
- ----------
Quarter Ended Six Months Ended
June 30, June 30,
2002 2001 2002 2001
- ---------------------------------------------------------------
(In millions)
Revenues $131.8 $117.6 $252.1 $309.9
Operating expenses 116.9 102.3 233.2 279.3
Workforce reduction costs 0.1 -- 0.1 --
Gains on sale of investments
and other assets 3.2 17.1 260.3 33.7
Depreciation and amortization 4.2 5.8 8.1 11.4
Taxes other than income taxes 1.1 0.9 2.1 1.8
- ---------------------------------------------------------------
Income from Operations $ 12.7 $ 25.7 $268.9 $ 51.1
===============================================================
Net Income Before
Cumulative Effect of
Change in Accounting
Principle $4.6 $ 2.2 $162.1 $ 6.7
Cumulative Effect of Change
in Accounting Principle -- -- -- 8.5
- ---------------------------------------------------------------
Net Income $4.6 $ 2.2 $162.1 $15.2
===============================================================
Net Income (Loss) Before
Special Items Included
in Operations $2.7 $(8.1) $ (4.1) $(13.7)
Gains on sale of
investments and
other assets 1.9 10.3 166.2 20.4
- ---------------------------------------------------------------
Net Income Before
Cumulative Effect of
Change in Accounting
Principle $4.6 $ 2.2 $162.1 6.7
Cumulative Effect of Change
in Accounting Principle -- -- -- 8.5
- ---------------------------------------------------------------
Net Income $4.6 $ 2.2 $162.1 $ 15.2
===============================================================
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 13 provides a reconciliation
of operating results by segment to our Consolidated Financial Statements.
During the quarter ended June 30, 2002, income from operations at our other
nonregulated businesses decreased compared to the same period of 2001 mostly
because of gains on the sale of securities in the second quarter of 2001 that
had a positive impact in that period. During the second quarter of 2001, we
recognized a $14.8 million pre-tax gain on the sale of one million shares of our
Orion investment. This was partially offset by growth of our energy services
business and better performance by our international business in the second
quarter of 2002.
During the six months ended June 30, 2002, income from operations at our
other nonregulated businesses increased compared to the same period of 2001
mostly because of the recognition of a $255.5 million pre-tax gain on the sale
of our investment in Orion as previously discussed in the Events of 2002 section
on page 23. This gain was partially offset by gains on the sale of securities in
2001 that had a positive impact in that period, including the sale of one
million shares of our Orion investment as discussed above and lower results from
our financial investments operation due to lower levels of investments and
volatile equity markets during 2002. In addition, our other nonregulated
businesses recorded an $8.5 million after-tax 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 that had a positive impact in that period.
As previously discussed in our 2001 Annual Report on Form 10-K, we decided
to sell certain non-core assets and accelerate the exit strategies on other
assets that we will continue to hold and own over the next several years. These
assets include approximately 1,300 acres of land holdings in various stages of
development located in seven sites in the central Maryland region, an operating
waste water treatment plant located in Anne Arundel County, Maryland, all of our
18 senior-living facilities, and certain international power projects. While our
intent is to dispose of these assets, market conditions and other events beyond
our control may affect the actual sale of these assets. In addition, a future
decline in the fair value of these assets could result in additional losses. In
addition, we initiated a liquidation program for our financial investments
operation and expect to sell substantially all of our investments in this
operation by the end of 2003. Through June 30, 2002, we liquidated approximately
50% of our investment portfolio since the beginning of the year.
Our remaining real estate projects are partially or substantially developed.
Our strategy is to hold and in some cases further develop these projects to
increase their value. However, if we were to sell these projects in the current
market, we may have losses that could be material, although the amount of the
losses is hard to predict.
Consolidated Nonoperating Income and Expenses
- ---------------------------------------------
Fixed Charges
- -------------
During the quarter ended June 30, 2002, total fixed charges increased compared
to the same period of 2001 mostly because of a higher level of debt outstanding.
During the six months ended June 30, 2002, total fixed charges decreased
compared to the same period of 2001 mostly because of lower short-term interest
rates partially offset by a higher level of debt outstanding.
Income Taxes
- ------------
During the quarter and six months ended June 30, 2002, our total income taxes
increased compared to the same periods of 2001 mostly because of higher taxable
income.
44
Financial Condition
- -------------------
Cash Flows
- ----------
Cash provided by operations was $335.5 million for the six months ended
June 30, 2002 compared to $261.0 million in 2001.
For the six months ended June 30, 2002, cash provided by investing
activities was $295.5 million compared to cash used in investing activities of
$568.5 million in 2001. The increase during 2002 was primarily due to the sale
of Orion and COPT that generated $555.4 million in cash proceeds, as well as the
liquidation program associated with our investment portfolio and a decrease in
capital spending due to the termination of all planned development projects.
Cash used in financing activities for the six months ended June 30, 2002 was
$450.4 million compared to cash provided of $236.6 million in 2001. The decrease
during 2002 was primarily due to higher repayment of debt in 2002 and the
issuance of common stock in 2001.
Security Ratings
- ----------------
Independent credit-rating agencies rate Constellation Energy's 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.
The factors that credit rating agencies consider in establishing
Constellation Energy's and BGE's credit ratings include, but are not limited to,
cash flows, liquidity, and the amount of debt as a component of total
capitalization. All Constellation Energy and BGE credit ratings have stable
outlooks. At the date of this report, our credit ratings were as follows:
Standard Moody's
& Poors Investors Fitch-
Rating Group Service Ratings
- ---------------------------------------------------------
Constellation Energy
--------------------
Commercial Paper A-2 P-2 F-2
Senior Unsecured Debt BBB+ Baa1 A-
BGE
---
Commercial Paper A-2 P-1 F-1
Mortgage Bonds A A1 A+
Senior Unsecured Debt BBB+ A2 A
Trust Originated
Preferred Securities
and Preference Stock BBB Baa1 A-
Available Sources of Funding
- ----------------------------
As previously discussed in our 2001 Annual Report on Form 10-K, we decided to
sell certain non-core assets to focus on our core strategies. We expect to use
the proceeds from these sales to reduce our debt and fund our merchant energy
business. In addition, we issued $1.8 billion of debt and established $1.28
billion of credit facilities during 2002. We continuously monitor our liquidity
requirements and believe that our facilities and access to the capital markets
provide sufficient liquidity to meet our business requirements. We discuss our
available sources of funding in more detail below.
Constellation Energy
- --------------------
In addition to the $1.8 billion of debt issued in March 2002, Constellation
Energy has a commercial paper program where it can issue short-term notes to
fund its subsidiaries. In June 2002, Constellation Energy established a 364-day
revolving credit facility totaling $640 million, and a $640 million three-year
revolving credit facility. These two new facilities will support our issuances
of commercial paper and letters of credit along with a previously established
$188.5 million revolving credit facility that expires in June 2003. These
facilities also can issue letters of credit up to approximately $1.1 billion. As
of June 30, 2002, Constellation Energy had $257.4 million in outstanding letters
of credit that results in approximately $1.2 billion of unused credit
facilities. Constellation Energy also has access to interim lines of credit as
required from time to time to support its outstanding commercial paper.
BGE
- ---
BGE maintains $150.0 million in annual committed bank lines of credit and a $50
million bank revolving credit agreement to support its commercial paper program.
The $50 million 364-day agreement expires in late 2002. As of June 30, 2002, BGE
had no outstanding commercial paper, which results in $200.0 million in unused
credit facilities. BGE also has access to interim lines of credit as required
from time to time to support its outstanding commercial paper and maintains a
program to sell up to $25 million of receivables.
In July 2002, BGE announced a partial call of $11.7 million principal amount
of its 7 1/2% Series, due April 15, 2023 First Refunding Mortgage Bonds in
connection with its annual sinking fund. Bonds called will be redeemed in whole
or in part on August 28, 2002 at the price of 100% of principal, plus accrued
interest from April 15, 2002 to August 28, 2002.
Other Nonregulated Businesses
- -----------------------------
BGE Home Products & Services maintains a program to sell up to $50 million of
receivables. ComfortLink has a revolving credit agreement totaling $50 million
to provide liquidity for short-term financial needs, which will expire in
September 2002.
If we can get a reasonable value for our remaining real estate projects 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.
45
Capital Resources
- -----------------
Our business requires a great deal of capital. Our estimated annual amounts for
the years 2002 and 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 2002 and 2003 include estimates of spending 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 construction or acquisition,
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 51.
Calendar Year Estimates
2002 2003
--------------------------------------------------
(In millions)
Nonregulated Capital
Requirements:
Merchant Energy
Construction program $139 $--
Steam generators 91 65
Environmental controls 67 16
Continuing requirements
(including nuclear fuel) 315 199
--------------------------------------------------
Total Merchant Energy 612 280
Other Nonregulated 38 34
--------------------------------------------------
Total Nonregulated capital
requirements 650 314
--------------------------------------------------
Utility Capital Requirements:
Regulated electric 163 174
Regulated gas 60 56
--------------------------------------------------
Total Utility capital
requirements 223 230
--------------------------------------------------
Total capital requirements $873 $544
==================================================
Table does not include amounts for the acquisition of NewEnergy. We discuss this
acquisition in the Events of 2002 section on page 25.
Capital Requirements
- --------------------
Merchant Energy Business
Our merchant energy business will require additional funding for power projects
under construction and growing its origination and risk management operation.
These capital requirements include:
o Construction expenditures for approximately 2,200 megawatts of natural
gas-fired peaking and combined cycle production facilities in various
regions of North America. In the second quarter of 2002, our Rio Nogales
facility and certain units of our Oleander facility were placed in
service.
o Cost 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.
Replacement of the steam generators will allow us to operate these units
through our operating license periods. The 2002 steam generator
replacement for Unit 1 was completed at the end of June 2002. We expect
the 2003 steam generator replacement to occur during the 2003 refueling
outage for Unit 2.
o Construction expenditures for improvements to generating plants,
including costs of complying with the Environmental Protection Agency
(EPA), Maryland, and Pennsylvania nitrogen oxides (NOx) emissions
regulations. We discuss the NOx regulations and timing of expenditures
in the Environmental Matters section of the Notes to the Consolidated
Financial Statements beginning on page 15.
The above table does not include the financing for the High Desert 750
megawatt gas-fired generation project in California, which is under an operating
lease with a term through February 2006. As an operating lease, we do not record
any assets or debt associated with the project in our Consolidated Balance
Sheets. We are leasing the project and supervising its construction.
Under the terms of the lease, we are required to make payments that
represent all or a portion of the lease balance if one of the following events
occurs: termination of construction prior to completion or our default under the
lease.
Under certain circumstances, we may be required to either post cash
collateral equal to the outstanding lease balance or we may elect to purchase
the property for the outstanding lease balance. At any time during the term of
the lease we have the right to pay off the lease and acquire the asset from the
lessor. At June 30, 2002, the outstanding lease balance plus other committed
expenses was $582.9 million.
46
At the conclusion of the lease term in 2006, we have the following options:
o renew the lease upon approval of the lessors,
o elect to purchase the property for a price equal to the lease balance
at the end of the term, or
o request the lessor to sell the property.
If we request the lessor to sell the property, we guarantee the sale
proceeds up to approximately 83% of the lease balance. The lease balance at the
end of the term is currently estimated to be $600 million, which represents the
estimated cost of the project; however, this may vary based on the ultimate cost
of construction and interest incurred during the construction period.
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
- --------------------------------
Merchant Energy Business
- ------------------------
Funding for the expansion of our merchant energy business is expected from
internally generated funds, commercial paper, issuances of long-term debt and
equity, leases, and other financing instruments issued by Constellation Energy
and its subsidiaries. We expect to fund the NewEnergy acquisition with available
sources of funding at the date of acquisition.
The projects that our merchant energy business develop typically require
substantial capital investment. Most of the projects recently constructed or
currently under construction are funded through corporate borrowings by
Constellation Energy. Certain other projects in which we have an interest are
financed primarily with non-recourse debt that is repaid from the project's cash
flows. This debt is collateralized by interests in the physical assets, major
project contracts and agreements, cash accounts and, in some cases, the
ownership interest in that project.
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.
BGE
- ---
Funding for utility capital expenditures is expected from internally generated
funds. During 2002 and 2003, we expect our regulated utility business to provide
at least 150% of the cash needed to meet the capital requirements for its
operations, excluding cash needed to retire debt or fund corporate obligations.
If necessary, additional funding may be obtained from 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. BGE also participates in a cash pool
with Constellation Energy as discussed in the Notes to Consolidated Financial
Statements section on page 19.
Other Nonregulated Businesses
- -----------------------------
Funding for our other nonregulated businesses is expected from internally
generated funds, commercial paper issuances, issuances of long-term debt of
Constellation Energy, sales of securities and assets, and/or from time to time
equity contributions from Constellation Energy. BGE Home Products & Services can
continue to fund capital requirements through sales of receivables. ComfortLink
has a revolving credit agreement totaling $50 million to provide liquidity for
short-term financial needs, which will expire in September 2002.
Our ability to sell or liquidate securities and assets will depend on market
conditions, and we cannot give assurances that these sales or liquidations could
be made. We discuss our remaining real estate projects and market conditions in
the Other Nonregulated Businesses section on page 44.
Committed Amounts
- -----------------
Our total contractual and contingent obligations as of June 30, 2002 are shown
in the following table:
Payments/Expiration
------------------------------------------------------
2002 2003-2004 2005-2006 Thereafter Total
- ------------------------------------------------------------------------
(In millions)
Contractual Obligations
- -----------------------
Short-term borrowings $15.5 $ -- $ -- $ -- $ 15.5
Nonregulated
long-term debt* 7.2 49.2 301.4 2,145.3 2,503.1
BGE long-term debt* 342.7 438.1 508.0 920.0 2,208.8
BGE preference stock -- -- -- 190.0 190.0
Fuel and transportation 176.5 356.9 81.9 12.8 628.1
Purchased capacity
and energy 27.4 48.6 35.7 89.2 200.9
Operating leases 7.1 76.7 61.6 164.5 309.9
Capital and loan
commitments ** 56.2 20.4 -- -- 76.6
- ------------------------------------------------------------------------
Total contractual
obligations 632.6 989.9 988.6 3,521.8 6,132.9
- ------------------------------------------------------------------------
Contingent Obligations
- ----------------------
Letters of credit 239.7 17.7 -- -- 257.4
Guarantees, net*** 566.2 89.8 688.4 214.4 1,558.8
- ------------------------------------------------------------------------
Total contingent
obligations 805.9 107.5 688.4 214.4 1,816.2
- ------------------------------------------------------------------------
Total obligations $1,438.5 $1,097.4 $1,677.0 $3,736.2 $7,949.1
========================================================================
*Amounts reflected in long-term debt maturities do not include $394 million
investors may require us to repay early through put options and remarketing
features.
**Amounts related to capital expenditures are included for applicable
periods in our capital requirements table on page 46.
*** Guarantees in the above table are shown net of liabilities recorded at
June 30, 2002 in our Consolidated Balance Sheets.
47
While we included our contingent obligations in the table on the previous
page, we do not expect to fund the full amounts under the letters of credit and
guarantees.
Lease payments under the High Desert operating lease are reflected in the
table on the previous page. The lease balance at the end of the lease term is
currently estimated to be $600 million. This amount is included as a guarantee
in the table on the previous page.
The table on the previous page does not include the fixed payment portions
of our mark-to-market energy assets and liabilities primarily related to
capacity payments under tolling arrangements. We discuss the expected settlement
terms of these contracts on page 36.
Liquidity Provisions
- --------------------
We have certain agreements that contain provisions that would require additional
collateral upon significant credit rating decreases in the Senior Unsecured Debt
of Constellation Energy. Decreases in Constellation Energy's credit ratings
would not trigger an early payment on any of our credit facilities. However,
under counterparty contracts related to our origination and risk management
operation, where we are obligated to post collateral, we estimate that we would
have additional collateral obligations based on downgrades to the following
credit ratings for our Senior Unsecured Debt:
Credit Ratings Level Below Incremental Cumulative
Downgraded Current Rating Obligations Obligations
- -------------------------------------------------------------
(In millions)
BBB/Baa2 1 $ 50 $ 50
BBB-/Baa3 2 60 110
Below investment
grade 3 405 515
At June 30, 2002, we had approximately $1.2 billion of unused credit
facilities and $251.0 million of cash available to meet these potential
requirements. However, based on market conditions and contractual obligations at
the time of such a downgrade, we could be required to post collateral in an
amount which could exceed the amounts specified above and which could be
material.
In many cases customers of our origination and risk management operation
rely on the creditworthiness of Constellation Energy. A decline below investment
grade by Constellation Energy would negatively impact the business prospects of
that operation.
The credit facilities of Constellation Energy and BGE have limited material
adverse change clauses that only consider a material change in financial
condition and are not directly affected by decreases in credit ratings. If these
clauses are violated, the lending institutions can decline making new advances
or issuing new letters of credit, but cannot accelerate existing amounts
outstanding. The credit facilities of Constellation Energy contain a provision
requiring Constellation Energy to maintain a ratio of debt to capitalization
equal to or less than 0.65. The long-term debt indentures of Constellation
Energy and BGE do not contain material adverse change clauses or financial
covenants.
Constellation Energy also provides credit support to Calvert Cliffs and Nine
Mile Point to ensure these plants have funds to meet expenses and obligations to
safely operate and maintain the plants.
Other Matters
- -------------
Environmental Matters
- ---------------------
We are subject to federal, state, and local laws and regulations that work to
improve or maintain the quality of the environment. If certain substances were
disposed of, or released at any of our properties, whether currently operating
or not, these laws and regulations require us to remove or remedy the effect on
the environment. This includes Environmental Protection Agency Superfund sites.
You will find details of our environmental matters in the Environmental
Matters section of the Notes to Consolidated Financial Statements beginning on
page 14 and in our 2001 Annual Report on Form 10-K in Item 1. Business -
Environmental Matters. These details include financial information. Some of the
information is about costs that may be material.
Accounting Standards Issued
- ---------------------------
We discuss recently issued accounting standards in the Accounting Standards
Issued section of the Notes to Consolidated Financial Statements on page 20.
Item 3. Quantitative and Qualitative Disclosures About Market Risk
- ------------------------------------------------------------------
We discuss the following information related to our market risk:
o financing activities and SFAS No. 133 hedging activities sections in the
Notes to Consolidated Financial Statements beginning on page 14,
o activities of our origination and risk management operation in the
Merchant Energy Business section of Management's Discussion and Analysis
beginning on page 32, and
o changes to our business environment in the Business Environment section
of Management's Discussion and Analysis beginning on page 27.
48
PART II.
- --------
OTHER INFORMATION
- -----------------
Item 1. Legal Proceedings
- ------- -----------------
California
- ----------
Baldwin Associates, Inc. v. Gray Davis, Governor of California and 22 other
defendants (including Constellation Power Development, Inc., a subsidiary of
Constellation Power, Inc.) -- This class action lawsuit was filed on October 5,
2001 in the Superior Court, County of San Francisco. The action seeks damages of
$43 billion, recession and reformation of approximately 38 long-term power
purchase contracts, and an injunction against improper spending by the state of
California.
Constellation Power Development, Inc. is named as a defendant but does not
have a power purchase agreement with the State of California. However, our High
Desert Power Project does have a power purchase agreement with the California
Department of Water Resources. In 2002, the court issued an order to the
plaintiff asking that he show cause why he had not yet served the defendants. In
April 2002, a second show cause order was issued. The plaintiff had until June
15, 2002 to respond. A show cause hearing was held on August 5, 2002 and the
plaintiff did not appear. A hearing is scheduled for October 7, 2002 for the
plaintiff to show cause why the case should not be dismissed.
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. The Court scheduled a briefing process
for the motion to certify the case as a class action suit for the beginning of
2003. 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.
Asbestos
- --------
Since 1993, BGE has been involved in several actions concerning asbestos. The
actions are based upon the theory of "premises liability," alleging that BGE
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. BGE is
involved in these claims with approximately 70 other defendants. Approximately
565 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 beginning in the summer
of 1993. BGE does not know the specific facts necessary to estimate its
potential liability for these claims. The specific facts BGE does not know
include:
o the identity of BGE's facilities at which the plaintiffs allegedly
worked as contractors,
o the names of the plaintiff's employers, and
o the date on which the exposure allegedly occurred.
To date, 47 of these cases were settled for amounts that were not
significant.
The second type is claims by one manufacturer--Pittsburgh Corning Corp.
(PCC)--against BGE and approximately eight others, as third-party defendants. On
April 17, 2000, PCC declared bankruptcy, and BGE does 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 375 cases have been resolved, all without any payment by BGE. BGE
does not know the specific facts necessary to estimate its potential liability
for these claims. The specific facts we do not know include:
o the identity of BGE facilities containing asbestos manufactured by the
manufacturer,
o the relationship (if any) of each of the individual plaintiffs to BGE,
o the settlement amounts for any individual plaintiffs who are shown to
have had a relationship to BGE, and
o the dates on which/places at which the exposure allegedly occurred.
Until the relevant facts for both types of claims are determined, BGE is
unable to estimate what its 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, the potential liability could be
material.
Asset Transfer Order
- --------------------
On July 6, 2000, the Mid-Atlantic Power Supply Association (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 issued an order on
September 29, 2000 upholding the Maryland PSC's order on the asset transfer.
MAPSA filed an appeal with the Maryland Court of Special Appeals. On April
1, 2002, the Maryland Court
49
of Special Appeals ruled against MAPSA on each of its arguments.
MAPSA did not file an appeal to this decision. Accordingly, this matter is
now closed.
Restructuring Order
- -------------------
In early December 1999, 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.
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) However,
MAPSA filed several appeals of this decision with several courts. On May 24,
2000, the Circuit Court dismissed both the Trigen and Sweetheart Cup appeals.
On September 29, 2000, the Baltimore City Circuit Court issued an order
upholding the Restructuring Order.
MAPSA filed an appeal with the Maryland Court of Special Appeals. On
April 1, 2002, the Maryland Court of Special Appeals ruled against MAPSA on each
of its arguments.
MAPSA did not file an appeal to this decision. Accordingly, this matter is
now closed.
Other
- -----
McCray, et. al .v. Baltimore Gas and Electric Company-- On June 10, 2002, a suit
was filed in the Circuit Court of Baltimore City, Maryland seeking a total of
$585 million in compensatory and punitive damages from BGE as a result of a fire
in a home that caused five fatalities. Electricity to the home was shut off.
While discovery in this suit has not yet begun, BGE believes that this case is
without merit.
Item 4. Submission of Matters to a Vote of Security Holders
- ------- ---------------------------------------------------
On May 24, 2002, we held our annual meeting of shareholders. At that meeting,
the following matters were voted upon:
1. All of the Directors nominated by Constellation Energy Group were
elected as follows:
COMMON SHARES CAST:
------------------
For Against Abstain
--- ------- -------
Roger W. Gale 136,957,982 9,105,134 3,919,330
Dr. Freeman A. Hrabowski, III 144,148,940 1,914,176 3,919,330
Nancy Lampton 144,352,057 1,711,059 3,919,330
Adm. Charles R. Larson * 144,749,102 1,314,014 3,919,330
Christian H. Poindexter 140,878,484 5,184,632 3,919,330
All other directors whose term of office continued after the date of
this meeting are:
James T. Brady James R. Curtiss
Douglas L. Becker Edward J. Kelly, III
Frank P. Bramble, Sr. Robert J. Lawless
Beverly B. Byron Mayo A. Shattuck, III
Edward A. Crooke Michael D. Sullivan
* On July 5, 2002, Adm. Charles R. Larson resigned from the Board of Directors.
2. The ratification of PricewaterhouseCoopers, LLP as independent
accountants was approved. With respect to holders of common stock, the
number of affirmative votes cast was 143,619,000, the number of votes
cast against was 5,266,496, and the number of abstentions was
1,251,706.
3. The proposal concerning approval of the executive long-term incentive
plan was approved. With respect to holders of common stock, the number
of affirmative votes cast was 131,608,867, the number of votes cast
against was 15,771,163, and the number of abstentions was 2,758,239.
4. The proposal concerning approval of the executive annual incentive plan
was approved. With respect to holders of common stock, the number of
affirmative votes cast was 133,947,074, the number of votes cast
against was 13,362,460, and the number of abstentions was 2,828,795.
5. The shareholder proposal concerning hiring Constellation Energy's
auditors for non-audit work was defeated. With respect to holders of
common stock, the number of affirmative votes cast was 16,550,514, the
number of votes cast against was 111,279,666, and the number of
abstentions was 3,904,137.
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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 the timing and extent of changes in commodity prices for energy
including coal, natural gas, oil, electricity, and emission allowances,
o the timing and extent of deregulation of, and competition in, the
energy markets in North America, and the rules and regulations adopted on
a transitional basis in those markets,
o the conditions of the capital markets, interest rates, availability of
credit, liquidity, and general economic conditions, as well as,
Constellation Energy's and BGE's ability to maintain their current credit
ratings,
o the effectiveness of Constellation Energy's risk management policies and
procedures and the ability of our counterparties to satisfy their
financial commitments,
o the liquidity and competitiveness of wholesale markets for energy
commodities,
o operational factors affecting the start-up or ongoing commercial
operations of our generating facilities (including nuclear facilities)
and BGE's transmission and distribution facilities, including
catastrophic weather related damages, unscheduled outages or repairs,
unanticipated changes in fuel costs or availability, unavailability of
gas transportation or electric transmission services, workforce issues,
terrorism, liabilities associated with catastrophic events, and other
events beyond our control,
o the inability of BGE to recover all its costs associated with providing
electric retail customers service during the electric rate freeze period,
o the effect of weather and general economic and business conditions on
energy supply, demand, and prices,
o regulatory or legislative developments that affect distribution rates and
revenues, demand for energy, or increase costs, including costs related
to nuclear power plants, safety, or environmental compliance,
o the actual outcome of uncertainties associated with assumptions and
estimates using judgment when applying critical accounting policies and
preparing financial statements, including factors that are estimated in
applying mark-to-market accounting, such as variable contract quantities
and the value of mark-to-market assets and liabilities determined using
models,
o losses on the sale or write down of assets due to impairment events or
changes in management intent with regard to either holding or selling
certain assets,
o cost and other effects of legal and administrative proceedings that may
not be covered by insurance, including environmental liabilities, and
o operation of our generation assets in a deregulated market without the
benefit of a fuel rate adjustment clause.
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.
Changes may occur after that date, and neither Constellation Energy nor BGE
assume responsibility to update these forward looking statements.
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, 2002:
None Filed
51
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, each
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
CONSTELLATION ENERGY GROUP, INC.
-----------------------------------------------
(Registrant)
BALTIMORE GAS AND ELECTRIC COMPANY
-----------------------------------------------
(Registrant)
Date: August 14, 2002 /s/ E. Follin Smith
---------------- ---------------------------------------------
E. Follin Smith, Senior Vice President on
behalf of each Registrant and as Principal
Financial Officer of each Registrant
52