UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For The Quarterly Period Ended SEPTEMBER 30, 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 of both registrants)
750 E. PRATT STREET BALTIMORE, MARYLAND 21202
-------------------------------------------------------------------------
(Address of principal executive offices) (Zip Code)
410-234-5000
----------------------------------------------------
(Registrants' telephone number, including area code)
NOT APPLICABLE
-----------------------------------------------------
(Former name, former address
and former fiscal year, if changed since last report)
Indicate by check mark whether the registrants (1) have filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months, and (2) have been subject to such filing
requirements for the past 90 days.
Yes X No
- ---------- ------------
Common Stock, without par value 164,737,286 shares outstanding of Constellation
Energy Group, Inc. on October 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........................................................ 27
Application of Critical Accounting Policies......................... 28
Events of 2002...................................................... 32
Strategy............................................................ 37
Business Environment................................................ 38
Results of Operations............................................... 42
Financial Condition................................................. 59
Capital Resources................................................... 60
Other Matters....................................................... 64
Item 3 -- Quantitative and Qualitative Disclosures About Market Risk.......... 64
Item 4 -- Controls and Procedures............................................. 64
Part II -- Other Information
Item 1 -- Legal Proceedings................................................... 65
Item 5 -- Other Information................................................... 67
Item 6 -- Exhibits and Reports on Form 8-K.................................... 67
Signature..................................................................... 68
Constellation Energy Group, Inc. Certifications............................... 69
Baltimore Gas and Electric Company Certifications............................. 71
2
CONSTELLATION ENERGY GROUP, INC. AND SUBSIDIARIES
PART 1 - FINANCIAL INFORMATION
Item 1 - Financial Statements
Consolidated Statements of Income (Unaudited)
Three Months Ended Nine Months Ended
September 30, September 30,
2002 2001 2002 2001
- ------------------------------------------------------------------------------------------------------------------------------------
(In millions, except per share amounts)
Revenues
Nonregulated revenues $ 606.5 $ 342.4 $1,415.2 $ 847.5
Regulated electric revenues 596.1 634.4 1,536.8 1,624.0
Regulated gas revenues 67.7 66.6 379.1 528.5
- ------------------------------------------------------------------------------------------------------------------------------------
Total revenues 1,270.3 1,043.4 3,331.1 3,000.0
Expenses
Operating expenses 732.9 568.5 2,041.8 1,832.8
Workforce reduction costs 12.5 -- 51.7 --
Impairment losses and other costs 24.6 -- 30.6 --
Depreciation and amortization 125.8 102.9 360.1 308.5
Taxes other than income taxes 66.5 55.2 195.7 169.6
- ------------------------------------------------------------------------------------------------------------------------------------
Total expenses 962.3 726.6 2,679.9 2,310.9
Gains on Sale of Investments and Other Assets -- 0.7 260.3 34.4
- ------------------------------------------------------------------------------------------------------------------------------------
Income from Operations 308.0 317.5 911.5 723.5
Other Income 8.3 2.3 21.1 5.3
Fixed Charges
Interest expense 78.4 66.2 228.9 216.8
Interest capitalized and allowance for borrowed
funds used during construction (8.5) (11.9) (40.4) (46.1)
BGE preference stock dividends 3.3 3.3 9.9 9.9
- ------------------------------------------------------------------------------------------------------------------------------------
Total fixed charges 73.2 57.6 198.4 180.6
- ------------------------------------------------------------------------------------------------------------------------------------
Income Before Income Taxes 243.1 262.2 734.2 548.2
Income Taxes
Current 86.0 86.5 253.7 198.9
Deferred 8.4 14.2 25.9 12.9
Investment tax credit adjustments (2.0) (2.1) (6.0) (6.1)
- ------------------------------------------------------------------------------------------------------------------------------------
Total income taxes 92.4 98.6 273.6 205.7
- ------------------------------------------------------------------------------------------------------------------------------------
Income Before Cumulative Effect of Change in Accounting Principle 150.7 163.6 460.6 342.5
Cumulative Effect of Change in Accounting Principle,
Net of Income Taxes of $5.6 -- -- -- 8.5
- ------------------------------------------------------------------------------------------------------------------------------------
Net Income $ 150.7 $ 163.6 $ 460.6 $ 351.0
====================================================================================================================================
Earnings Applicable to Common Stock $ 150.7 $ 163.6 $ 460.6 $ 351.0
====================================================================================================================================
Average Shares of Common Stock Outstanding 164.4 163.7 164.0 159.8
Earnings Per Common Share and Earnings Per Common Share - Assuming
Dilution Before Cumulative Effect of Change in Accounting Principle $0.92 $1.00 $2.81 $2.14
Cumulative Effect of Change in Accounting Principle -- -- -- 0.06
- ------------------------------------------------------------------------------------------------------------------------------------
Earnings Per Common Share and
Earnings Per Common Share - Assuming Dilution $0.92 $1.00 $2.81 $2.20
Dividends Declared Per Common Share $0.24 $0.12 $0.72 $0.36
Consolidated Statements of Comprehensive Income (Unaudited)
Three Months Ended Nine Months Ended
September 30, September 30,
2002 2001 2002 2001
- ------------------------------------------------------------------------------------------------------------------------------------
(In millions)
Net Income $150.7 $163.6 $460.6 $351.0
Reclassification adjustment - gains on sale of investments
included in net income, net of taxes -- (0.2) (154.9) (9.8)
Other comprehensive income (loss), net of taxes (70.4) (18.1) (87.5) 170.8
- ------------------------------------------------------------------------------------------------------------------------------------
Comprehensive Income Before Cumulative Effect of
Change in Accounting Principle 80.3 145.3 218.2 512.0
Cumulative Effect of Change in Accounting Principle,
Net of Income Taxes of $22.6 -- -- -- (35.5)
- ------------------------------------------------------------------------------------------------------------------------------------
Comprehensive Income $ 80.3 $145.3 $218.2 $476.5
====================================================================================================================================
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
September 30, December 31,
2002* 2001
- ---------------------------------------------------------------------------------------------------------------------------------------
(In millions)
Assets
Current Assets
Cash and cash equivalents $ 458.3 $ 72.4
Accounts receivable (net of allowance for uncollectibles
of $42.2 and $22.8, respectively) 830.8 738.9
Trading securities 76.0 178.2
Mark-to-market energy assets 285.6 398.4
Fuel stocks 125.9 108.0
Materials and supplies 222.0 205.3
Prepaid taxes other than income taxes 93.3 64.7
Other 170.9 94.3
- ---------------------------------------------------------------------------------------------------------------------------------------
Total current assets 2,262.8 1,860.2
- ---------------------------------------------------------------------------------------------------------------------------------------
Investments and Other Assets
Real estate projects and investments 94.7 210.7
Investments in qualifying facilities and power projects 446.1 499.1
Investment in Orion Power Holdings, Inc. -- 442.5
Financial investments 37.5 60.7
Nuclear decommissioning trust funds 627.3 683.5
Mark-to-market energy assets 1,256.5 1,819.8
Goodwill 106.0 --
Other 309.7 207.4
- ---------------------------------------------------------------------------------------------------------------------------------------
Total investments and other assets 2,877.8 3,923.7
- ---------------------------------------------------------------------------------------------------------------------------------------
Property, Plant and Equipment
Regulated property, plant and equipment 5,026.7 4,948.7
Nonregulated generation property, plant and equipment 6,733.8 6,551.1
Other nonregulated property, plant and equipment 224.7 192.9
Nuclear fuel (net of amortization) 210.0 169.5
Accumulated depreciation (4,322.4) (4,161.8)
- ---------------------------------------------------------------------------------------------------------------------------------------
Net property, plant and equipment 7,872.8 7,700.4
- ---------------------------------------------------------------------------------------------------------------------------------------
Deferred Charges
Regulatory assets (net) 426.4 463.8
Other 140.2 129.5
- ---------------------------------------------------------------------------------------------------------------------------------------
Total deferred charges 566.6 593.3
- ---------------------------------------------------------------------------------------------------------------------------------------
Total Assets $13,580.0 $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
September 30, December 31,
2002* 2001
- ---------------------------------------------------------------------------------------------------------------------------------------
(In millions)
Liabilities and Equity
Current Liabilities
Short-term borrowings $ 18.6 $ 975.0
Current portion of long-term debt 630.1 1,406.7
Accounts payable 541.3 523.3
Mark-to-market energy liabilities 191.0 323.3
Dividends declared 42.8 23.0
Accrued interest 129.8 57.7
Other 411.5 250.5
- ---------------------------------------------------------------------------------------------------------------------------------------
Total current liabilities 1,965.1 3,559.5
- ---------------------------------------------------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities
Deferred income taxes 1,299.0 1,431.0
Mark-to-market energy liabilities 855.6 1,476.5
Net pension liability 113.2 173.3
Postretirement and postemployment benefits 347.4 330.9
Deferred investment tax credits 87.6 93.4
Other 257.7 165.2
- ---------------------------------------------------------------------------------------------------------------------------------------
Total deferred credits and other liabilities 2,960.5 3,670.3
- ---------------------------------------------------------------------------------------------------------------------------------------
Long-term Debt
Long-term debt of Constellation Energy 2,600.0 935.0
Long-term debt of nonregulated businesses 362.2 769.1
First refunding mortgage bonds of BGE 904.9 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 (13.4) (5.2)
Current portion of long-term debt (630.1) (1,406.7)
- ---------------------------------------------------------------------------------------------------------------------------------------
Total long-term debt 4,391.7 2,712.5
- ---------------------------------------------------------------------------------------------------------------------------------------
Minority Interests 104.2 101.7
BGE Preference Stock Not Subject to Mandatory Redemption 190.0 190.0
Common Shareholders' Equity
Common stock 2,068.6 2,042.2
Retained earnings 1,952.4 1,611.5
Accumulated other comprehensive (loss) income (52.5) 189.9
- ---------------------------------------------------------------------------------------------------------------------------------------
Total common shareholders' equity 3,968.5 3,843.6
- ---------------------------------------------------------------------------------------------------------------------------------------
Commitments, Guarantees, and Contingencies (see Notes)
Total Liabilities and Equity $13,580.0 $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)
Nine Months Ended
September 30,
2002 2001
- ---------------------------------------------------------------------------------------------------------------------------------------
(In millions)
Cash Flows From Operating Activities
Net income $ 460.6 $ 351.0
Adjustments to reconcile to net cash provided by operating activities
Cumulative effect of change in accounting principle -- (8.5)
Depreciation and amortization 403.6 343.1
Deferred income taxes 25.9 12.9
Investment tax credit adjustments (6.0) (6.1)
Deferred fuel costs 24.4 56.4
Pension and postemployment benefits (114.0) 19.5
Gains on sale of investments (260.3) (34.4)
Workforce reduction costs 51.7 --
Impairment losses and other costs 30.6 --
Equity in earnings of affiliates less than (in excess of) dividends received 47.7 (6.9)
Changes in
Accounts receivable 114.0 (9.6)
Mark-to-market energy assets and liabilities (77.1) (6.8)
Materials, supplies and fuel stocks (34.6) (34.2)
Other current assets 87.0 (23.3)
Accounts payable (147.4) 12.9
Other current liabilities 121.7 157.4
Other (72.1) (180.1)
- ---------------------------------------------------------------------------------------------------------------------------------------
Net cash provided by operating activities 655.7 643.3
- ---------------------------------------------------------------------------------------------------------------------------------------
Cash Flows From Investing Activities
Purchases of property, plant and equipment (621.6) (1,003.9)
Acquisition of NewEnergy, net of cash acquired (207.8) --
Contributions to nuclear decommissioning trust funds (13.2) (17.6)
Purchases of marketable equity securities (0.2) (31.4)
Sales of marketable equity securities 130.9 80.8
Sales of investment in Orion Power Holdings, Inc. 454.1 26.2
Sales of real estate investments 123.9 --
Sales of property, plant and equipment 44.4 49.5
Other (26.7) (11.8)
- ---------------------------------------------------------------------------------------------------------------------------------------
Net cash used in investing activities (116.2) (908.2)
- ---------------------------------------------------------------------------------------------------------------------------------------
Cash Flows From Financing Activities
Net (maturity) issuance of short-term borrowings (956.4) 127.3
Proceeds from issuance of
Long-term debt 2,302.7 851.8
Common stock 19.6 504.4
Repayment of long-term debt (1,431.3) (1,244.9)
Common stock dividends paid (98.4) (101.0)
Other 10.2 8.6
- ---------------------------------------------------------------------------------------------------------------------------------------
Net cash (used in) provided by financing activities (153.6) 146.2
- ---------------------------------------------------------------------------------------------------------------------------------------
Net Increase (Decrease) in Cash and Cash Equivalents 385.9 (118.7)
Cash and Cash Equivalents at Beginning of Period 72.4 182.7
- ---------------------------------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of Period $ 458.3 $ 64.0
=======================================================================================================================================
Other Cash Flow Information
Cash paid during the period for:
Interest (net of amounts capitalized) $117.5 $178.8
Income taxes $160.4 $139.1
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 Nine Months Ended
September 30, September 30,
2002 2001 2002 2001
- ---------------------------------------------------------------------------------------------------------------------------------------
(In millions)
Revenues
Electric revenues $596.3 $634.6 $1,537.1 $1,624.4
Gas revenues 72.2 66.8 388.1 534.1
- ---------------------------------------------------------------------------------------------------------------------------------------
Total revenues 668.5 701.4 1,925.2 2,158.5
Expenses
Operating expenses:
Electric fuel and purchased energy 358.6 418.0 872.9 977.7
Gas purchased for resale 28.3 22.9 191.3 328.0
Operations and maintenance 92.9 83.3 259.1 256.9
Workforce reduction costs 3.3 -- 32.1 --
Depreciation and amortization 55.1 53.5 167.4 166.8
Taxes other than income taxes 43.0 43.3 129.1 132.6
- ---------------------------------------------------------------------------------------------------------------------------------------
Total expenses 581.2 621.0 1,651.9 1,862.0
- ---------------------------------------------------------------------------------------------------------------------------------------
Income from Operations 87.3 80.4 273.3 296.5
Other Income 3.0 2.6 7.9 1.6
Fixed Charges
Interest expense 34.2 39.1 108.4 120.6
Allowance for borrowed funds used during construction (0.3) -- (1.1) (1.4)
- ---------------------------------------------------------------------------------------------------------------------------------------
Total fixed charges 33.9 39.1 107.3 119.2
- ---------------------------------------------------------------------------------------------------------------------------------------
Income Before Income Taxes 56.4 43.9 173.9 178.9
Income Taxes
Current 7.9 17.9 73.9 78.2
Deferred 15.2 (0.6) (3.1) (6.3)
Investment tax credit adjustments (0.6) (0.5) (1.6) (1.7)
- ---------------------------------------------------------------------------------------------------------------------------------------
Total income taxes 22.5 16.8 69.2 70.2
- ---------------------------------------------------------------------------------------------------------------------------------------
Net Income 33.9 27.1 104.7 108.7
Preference Stock Dividends 3.3 3.3 9.9 9.9
- ---------------------------------------------------------------------------------------------------------------------------------------
Earnings Applicable to Common Stock $ 30.6 $ 23.8 $ 94.8 $ 98.8
=======================================================================================================================================
See Notes to Consolidated Financial Statements.
7
BALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARIES
PART 1 - FINANCIAL INFORMATION (CONTINUED)
Item 1 - Financial Statements
Consolidated Balance Sheets
September 30, December 31,
2002* 2001
- ---------------------------------------------------------------------------------------------------------------------------------------
(In millions)
Assets
Current Assets
Cash and cash equivalents $ 9.8 $ 37.4
Accounts receivable (net of allowance for uncollectibles
of $14.0 and $13.4 respectively) 321.9 295.2
Investment in cash pool, affiliated company 383.7 439.1
Accounts receivable, affiliated companies 257.7 133.4
Fuel stocks 54.7 52.3
Materials and supplies 32.9 33.1
Prepaid taxes other than income taxes 62.9 43.8
Other 15.9 36.3
- ---------------------------------------------------------------------------------------------------------------------------------------
Total current assets 1,139.5 1,070.6
- ---------------------------------------------------------------------------------------------------------------------------------------
Other Assets
Receivable, affiliated company -- 113.3
Other 82.1 74.5
- ---------------------------------------------------------------------------------------------------------------------------------------
Total other assets 82.1 187.8
- ---------------------------------------------------------------------------------------------------------------------------------------
Utility Plant
Plant in service
Electric 3,405.3 3,349.9
Gas 1,027.1 1,014.4
Common 491.6 498.1
- ---------------------------------------------------------------------------------------------------------------------------------------
Total plant in service 4,924.0 4,862.4
Accumulated depreciation (1,836.8) (1,751.4)
- ---------------------------------------------------------------------------------------------------------------------------------------
Net plant in service 3,087.2 3,111.0
Construction work in progress 98.2 81.8
Plant held for future use 4.5 4.5
- ---------------------------------------------------------------------------------------------------------------------------------------
Net utility plant 3,189.9 3,197.3
- ---------------------------------------------------------------------------------------------------------------------------------------
Deferred Charges
Regulatory assets (net) 426.4 463.8
Other 31.8 35.0
- ---------------------------------------------------------------------------------------------------------------------------------------
Total deferred charges 458.2 498.8
- ---------------------------------------------------------------------------------------------------------------------------------------
Total Assets $4,869.7 $4,954.5
=======================================================================================================================================
* Unaudited
See Notes to Consolidated Financial Statements.
Certain prior-period amounts have been reclassified to conform with the current
period's presentation.
8
BALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARIES
PART 1 - FINANCIAL INFORMATION (CONTINUED)
Item 1 - Financial Statements
Consolidated Balance Sheets
September 30, December 31,
2002* 2001
- ---------------------------------------------------------------------------------------------------------------------------------------
(In millions)
Liabilities and Equity
Current Liabilities
Current portion of long-term debt $ 593.7 $ 666.3
Accounts payable 68.7 63.6
Accounts payable, affiliated companies 77.7 92.6
Customer deposits 52.9 50.0
Accrued taxes 28.0 7.6
Accrued interest 41.1 37.0
Accrued vacation costs 17.8 21.7
Other 26.5 39.2
- ---------------------------------------------------------------------------------------------------------------------------------------
Total current liabilities 906.4 978.0
- ---------------------------------------------------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities
Deferred income taxes 497.9 503.1
Postretirement and postemployment benefits 276.1 266.1
Deferred investment tax credits 21.1 22.7
Decommissioning of federal uranium enrichment facilities 19.3 19.3
Other 14.0 17.2
- ---------------------------------------------------------------------------------------------------------------------------------------
Total deferred credits and other liabilities 828.4 828.4
- ---------------------------------------------------------------------------------------------------------------------------------------
Long-term Debt
First refunding mortgage bonds of BGE 904.9 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 25.0 71.0
Unamortized discount and premium (5.2) (3.3)
Current portion of long-term debt (593.7) (666.3)
- ---------------------------------------------------------------------------------------------------------------------------------------
Total long-term debt 1,499.1 1,821.7
- ---------------------------------------------------------------------------------------------------------------------------------------
Minority Interest 19.6 5.0
Preference Stock Not Subject to Mandatory Redemption 190.0 190.0
Common Shareholder's Equity
Common stock 911.9 711.9
Retained earnings 514.3 419.5
- ---------------------------------------------------------------------------------------------------------------------------------------
Total common shareholder's equity 1,426.2 1,131.4
- ---------------------------------------------------------------------------------------------------------------------------------------
Commitments, Guarantees, and Contingencies (see Notes)
Total Liabilities and Equity $4,869.7 $4,954.5
=======================================================================================================================================
* Unaudited
See Notes to Consolidated Financial Statements.
Certain prior-period amounts have been reclassified to conform with the current
period's presentation.
9
BALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARIES
PART 1 - FINANCIAL INFORMATION (CONTINUED)
Item 1 - Financial Statements
Consolidated Statements of Cash Flows (Unaudited)
Nine Months Ended
September 30,
2002 2001
- ---------------------------------------------------------------------------------------------------------------------------------------
(In millions)
Cash Flows From Operating Activities
Net income $ 104.7 $ 108.7
Adjustments to reconcile to net cash provided by operating activities
Depreciation and amortization 169.6 168.5
Deferred income taxes (3.1) (6.3)
Investment tax credit adjustments (1.6) (1.7)
Deferred fuel costs 24.4 56.4
Pension and postemployment benefits (42.0) 8.1
Workforce reduction costs 32.1 --
Allowance for equity funds used during construction (2.1) (2.2)
Changes in
Accounts receivable (37.7) (50.7)
Materials, supplies and fuel stocks (2.2) (27.8)
Other current assets 11.5 (22.3)
Accounts payable (9.8) 4.1
Other current liabilities 10.8 2.6
Other 23.8 8.0
- ---------------------------------------------------------------------------------------------------------------------------------------
Net cash provided by operating activities 278.4 245.4
- ---------------------------------------------------------------------------------------------------------------------------------------
Cash Flows From Investing Activities
Utility construction expenditures (excluding equity portion of AFC) (136.1) (172.0)
Investment in cash pool at parent 55.4 (2.1)
Other (22.0) (11.0)
- ---------------------------------------------------------------------------------------------------------------------------------------
Net cash used in investing activities (102.7) (185.1)
- ---------------------------------------------------------------------------------------------------------------------------------------
Cash Flows From Financing Activities
Net maturity of short-term borrowings -- 75.3
Proceeds from issuance of long-term debt -- 210.9
Repayment of long-term debt (393.4) (334.1)
Capital contribution from parent 200.0 --
Preference stock dividends paid (9.9) (9.9)
- ---------------------------------------------------------------------------------------------------------------------------------------
Net cash used in financing activities (203.3) (57.8)
- ---------------------------------------------------------------------------------------------------------------------------------------
Net (Decrease) Increase in Cash and Cash Equivalents (27.6) 2.5
Cash and Cash Equivalents at Beginning of Period 37.4 21.3
- ---------------------------------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of Period $ 9.8 $ 23.8
=======================================================================================================================================
Other Cash Flow Information
Cash paid during the period for:
Interest (net of amounts capitalized) $104.5 $122.8
Income taxes $ 22.4 $ 66.9
See Notes to Consolidated Financial Statements.
Certain prior-period amounts have been reclassified to conform with the current
period's presentation.
10
Notes to Consolidated Financial Statements
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
During 2002, we have incurred costs related to workforce reduction efforts
initiated in the fourth quarter of 2001 and additional initiatives undertaken in
the third quarter of 2002. We discuss these costs in more detail below.
2001 Programs
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 Voluntary Special Early Retirement Program (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, we recorded $35.1 million of net workforce
reduction costs associated with our workforce reduction initiatives. 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 $25.1 million involuntary severance accrual 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 recognized as
expense, of which BGE recognized $20.9 million. The remaining $9.2 million was
recognized by BGE as a regulatory asset related to its gas business.
In the second quarter of 2002, we recorded $16.3 million of net workforce
reduction costs. This amount included 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 recognized as
expense, of which BGE recognized $7.9 million. The remaining $3.0 million was
recognized by BGE as a regulatory asset related to its gas business.
In the third quarter of 2002, we recorded $6.0 million of additional costs
associated with our 2001 workforce reduction initiatives. This amount consisted
of a $5.2 million settlement charge for our basic, qualified pension plan under
SFAS No. 88 for additional lump-sum pension payments made during the period, and
an $0.8 million expense associated with deferred payments to employees eligible
for the VSERP.
The $6.0 million discussed above, included $5.3 million recognized as
expense, of which BGE recognized $3.3 million. The remaining $0.7 million was
recognized by BGE as a regulatory asset related to its gas business.
11
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 for our 2001 workforce reduction programs:
(In millions)
Severance liability balance at December 31, 2001 $ 25.1
VSERP elections in first quarter of 2002 52.9
Reduction of 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 severance accrual in
second quarter of 2002 (0.6)
---------
Amounts recorded in second quarter of 2002 18.2
Amounts recorded in third quarter of 2002 6.0
Cash severance payments made in 2002 (6.1)
Amount reflected in long-term
pension and postretirement obligations (77.7)
--------
Severance liability balance at September 30, 2002 $ 0.6
========
The amount reflected in long-term pension and postretirement obligations is
recorded as liabilities in "Net pension liability" and "Postretirement and
postemployment benefits" in our Consolidated Balance Sheets.
2002 Programs
In the third quarter of 2002, we recorded approximately $7.2 million of
workforce reduction costs associated with new initiatives expected to result in
the elimination of 118 positions at Calvert Cliffs Nuclear Power Plant (Calvert
Cliffs) and in our information technology organization. In accordance with EITF
94-3, we recognized a $7.2 million charge to expense for anticipated involuntary
severance costs associated with these workforce reductions. BGE recorded $0.6
million of this amount associated with the information technology organization.
In addition, we recorded $2.7 million of workforce reduction costs for the
expected elimination of 115 positions as a result of the closing of our BGE Home
retail merchandise stores. These costs are included in "Impairment losses and
other costs" in our Consolidated Statements of Income. We discuss the closing of
these stores in more detail on page 13.
Impairment Losses and Other Costs
Investments in Qualifying Facilities and Power Projects
Our merchant energy business holds up to a 50% ownership interest in 28
operating domestic energy projects that consist of electric generation, fuel
processing, or fuel handling facilities. Of these 28 projects, 20 are
"qualifying facilities" that receive certain exemptions and pricing under the
Public Utility Regulatory Policy Act of 1978 based on the facilities' energy
source or the use of a cogeneration process.
In the third quarter of 2002, we recorded impairment losses on certain of
these investments totaling $14.4 million pre-tax, or $9.9 million after-tax,
under the provisions of Accounting Principles Board Opinion (APB) No. 18, The
Equity Method of Accounting for Investments in Common Stock. At September 30,
2002, our investment in these projects consisted of the following:
Book Value Book Value
Before Pre-tax After-tax After
Project Type Write-down Write-down Write-down Write-down
- -------------------------------------------------------------------
(In millions)
Geothermal $151.4 $ 5.2 $3.4 $146.2
Coal 138.6 -- -- 138.6
Hydroelectric 63.0 -- -- 63.0
Biomass 55.6 -- -- 55.6
Fuel Processing 27.1 2.6 1.7 24.5
Solar 10.5 -- -- 10.5
Waste to Energy 6.6 6.6 4.8 --
- -------------------------------------------------------------------
Total $452.8 $14.4 $9.9 $438.4
===================================================================
The provisions of APB No. 18 require that an impairment loss be recognized
when an investment experiences a loss in value that is other than temporary.
During the third quarter of 2002, we performed an analysis of whether any of our
investments in qualifying facilities and power projects were impaired.
As a result of our analysis, we concluded that the declines in value of
particular investments in certain qualifying facilities and power projects were
other than temporary in nature under the provisions of APB No. 18 and we
recognized the following losses in the third quarter of 2002:
o We recognized a $5.2 million pre-tax, or $3.4 million after-tax, other than
temporary decline in value of our investment in a partnership that owns a
geothermal project in Nevada. This project experienced a well implosion
and we believe that the expected cash flows from the project will not be
sufficient to recover our equity interest in that partnership.
12
o We recognized a $2.6 million pre-tax, or $1.7 million after-tax, other than
temporary decline in value of our investment in a fuel processing site in
Pennsylvania where the expected cash flows from a sublease are no longer
expected to be sufficient to recover our lease costs associated with this
site.
o We recognized a $6.6 million pre-tax, or $4.8 million after-tax, other than
temporary decline in value of our investment in a partnership that owns a
waste burning power project in Michigan. At December 31, 2001, we
recognized a $6.1 million pre-tax impairment loss on this investment
because we expected operating cash flows would not be sufficient to pay
existing debt service and that we would not be able to recover our equity
investment. However, at that time, we believed that we would recover our
senior working capital loans receivable and accounts receivable for
operating the project. As of September 2002, the operating performance of
the project has not improved as expected, and we now believe the expected
future cash flows are no longer sufficient to recover these receivables.
Therefore, we recognized an additional impairment loss on this
investment.
We believe the current market conditions for our equity-method investments
that own geothermal, coal, hydroelectric, and fuel processing projects provide
sufficient positive cash flows to recover our investments. We continuously
monitor issues that potentially could impact future profitability of these
investments, including environmental and legislative initiatives. However,
should future events cause these investments to become uneconomic, our
investments in these projects could become impaired under the provisions of APB
No. 18.
We have an investment in a partnership that owns a geothermal project with a
book value of $93 million. Currently, the project is not generating at its
designed capacity. The project is drilling wells at this site to restore the
generation to its capacity. We expect the current well drilling to be successful
and the geothermal resource to be sufficient to enable the project to generate
adequate cash flows over the life of this project to recover our equity interest
in that investment. However, should current or future well drilling at this site
prove to be unsuccessful or become uneconomic, causing us not to make future
investments in this partnership, our investment in this partnership could become
impaired under the provisions of APB No. 18.
The ability to recover our costs in our equity-method investments that own
biomass and solar projects is partially dependent upon subsidies from the State
of California. Under the California Public Utility Act, subsidies currently
exist in that the California Public Utilities Commission requires electric
corporations to identify a separate rate component to fund the development of
renewable resources technologies, including solar, biomass, and wind facilities.
In addition, proposed legislation requires that each electric corporation
increase its total procurement of eligible renewable energy resources by at
least one percent per year so that 20% of its retail sales are procured from
eligible renewable energy resources by 2017. The proposed legislation also
requires the California Energy Commission to award supplemental energy payments
to electric corporations to cover above market costs of renewable energy.
Given the need for electric power and the desire for renewable resource
technologies, we believe California will continue to subsidize the use of
renewable energy to make these projects economical to operate. However, should
the California legislation fail to adequately support the renewable energy
initiatives, our equity-method investments in these types of projects could
become impaired under the provisions of APB No. 18, and any losses recognized
could be material.
Closing of BGE Home Retail Merchandise Stores
In September 2002, we announced our decision to close our BGE Home retail
merchandise stores. In connection with that decision, we recognized
approximately $9.3 million in exit costs. We recognized $2.7 million related to
expected severance costs as discussed in the Workforce Reduction Costs section
on page 12 and $2.5 million of costs in connection with the termination of
leases for the eight stores in accordance with EITF 94-3.
We also recognized $3.2 million for the write-off of unamortized leasehold
improvements in accordance with SFAS No. 144, Accounting for the Impairment or
Disposal of Long-Lived Assets, and $0.9 million for the write-down of inventory
to a lower-of-cost-or-market valuation in accordance with Accounting Research
Bulletin No. 43, Restatement and Revision of Accounting Research Bulletins. The
$0.9 million is included in "Operating expenses" in our Consolidated Statements
of Income.
Real Estate and International Investments
As discussed in our 2001 Annual Report on Form 10-K, we changed our strategy
from an intent to hold to an intent to sell for certain of our non-core assets.
During the third quarter of 2002, we determined that the fair value of several
real estate projects and our investment in an international power project
declined below their respective book values due to deteriorating market
conditions for these projects. Accordingly, we recorded losses that totaled $1.8
million for these projects in accordance with SFAS No. 144 and APB No. 18.
13
Sale of Senior-Living Facilities
On October 25, 2002, we sold all of our 18 senior-living facilities for $77.2
million that represents a combination of cash and the assumption by the buyer of
existing mortgages. The proceeds from the sale approximate the book value of
these facilities.
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.
Acquisition of NewEnergy
On September 9, 2002, we completed our purchase of AES NewEnergy, Inc. from AES
Corporation. Subsequent to the acquisition, we renamed AES NewEnergy, Inc. as
Constellation NewEnergy, Inc. (NewEnergy). NewEnergy is a leading national
provider of electricity, natural gas, and energy services, serving approximately
4,300 megawatts (MW) of load associated with large commercial and industrial
customers in competitive energy markets including the Northeast, Mid-Atlantic,
Midwest, Texas and California. We acquired 100% ownership of NewEnergy for cash
of $253.3 million including $1.4 million of direct costs associated with the
acquisition. We acquired cash of $45.5 million as part of the purchase. We
include NewEnergy in our Merchant Energy business segment.
Our preliminary purchase price allocation for the net assets acquired is as
follows:
At September 9, 2002 (In millions)
- ----------------------------------------------------
Cash $ 45.5
Other Current Assets 368.6
- ----------------------------------------------------
Total Current Assets 414.1
Net Property, Plant and Equipment 7.0
Goodwill 106.0
Other Assets 51.3
- ----------------------------------------------------
Total Assets Acquired 578.4
Current Liabilities 278.4
Deferred Credits and Other Liabilities 46.7
- ----------------------------------------------------
Net Assets Acquired $253.3
====================================================
We recorded the existing contracts at fair value as part of the purchase
price allocation. The preliminary net fair value of the contracts was $54.8
million. We recorded the fair value of these contracts as follows:
Net fair value of acquired contracts
- -------------------------------------------------
(In millions)
Current Assets $ 78.6
Noncurrent Assets 45.0
- -------------------------------------------------
Total Assets 123.6
- -------------------------------------------------
Current Liabilities 46.8
Noncurrent Liabilities 22.0
- -------------------------------------------------
Total Liabilities 68.8
- -------------------------------------------------
Net fair value of acquired contracts $ 54.8
=================================================
We will amortize this value over a period extending through 2007. The
weighted-average amortization period is approximately 2 years and represents the
expected contract duration.
Currently, we have the following items that have not been finalized that
could impact our purchase price allocation:
o further refinements to the preliminary valuation of the existing contracts,
o adjustments to the preliminary estimates of severance and relocation costs
recorded as current liabilities associated with the integration of
NewEnergy into our operations,
o certain tax matters, including the resolution of the net asset basis
calculation and certain state income taxes payable on the transaction
where we have up to 90 days after the closing to settle,
o results from outside appraisers hired to value potential other intangible
assets, and
o results from the independent audit of the closing balance sheet.
On a pro-forma basis, had the acquisition of NewEnergy occurred on the first
day of each of the periods presented below, our nonregulated revenues and total
revenues would have been as follows:
Three Months Ended Nine Months Ended
September 30, September 30,
2002 2001 2002 2001
- ------------------ --------- --------- --------- ---------
(In millions)
Nonregulated
revenues
As reported $ 606.5 $ 342.4 $1,415.2 $ 847.5
Pro-forma 854.2 566.6 2,203.6 1,339.8
Total revenues
As reported $1,270.3 $1,043.4 $3,331.1 $3,000.0
Pro-forma 1,518.0 1,267.6 4,119.5 3,492.3
We believe that the pro-forma impact on "Income before cumulative effect of
change in accounting principle," "Net income," and "Earnings per common share"
would not have been material had the acquisition of NewEnergy occurred on the
first day of each of the periods presented.
14
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 (such as
load-serving, tolling contracts, and power purchase agreements), 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 (until October 25, 2002), and
- own interests in international 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 included 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 September 2002, we
announced the closing of BGE Home's retail merchandise stores by December 2002
and in October 2002, we sold all of our senior-living facilities.
We have reclassified certain prior-period information for comparative
purposes based on our reportable operating segments.
15
Unallocated
Merchant Regulated Regulated Other Corporate
Energy Electric Gas Nonregulated Items and
Business Business Business Businesses Eliminations Consolidated
- --------------------------- -------------- -------------- ------------- -------------- --------------- -------------
For the three months ended September 30, (In millions)
2002
Unaffiliated revenues $ 473.0 $ 596.1 $ 67.7 $133.5 $ -- $1,270.3
Intersegment revenues 359.0 0.2 4.5 -- (363.7) --
- ---------------------------- ------------- -------------- ------------- -------------- ------------ ----------------
Total revenues 832.0 596.3 72.2 133.5 (363.7) 1,270.3
Net income (loss) 130.3 35.0 (4.1) (10.5) -- 150.7
2001
Unaffiliated revenues $ 230.0 $ 634.4 $ 66.6 $112.4 $ -- $1,043.4
Intersegment revenues 401.4 0.2 0.2 -- (401.8) --
- ---------------------------- ------------- -------------- ------------- -------------- ------------ ----------------
Total revenues 631.4 634.6 66.8 112.4 (401.8) 1,043.4
Net income (loss) 144.9 27.3 (2.3) (6.3) -- 163.6
For the nine months ended September 30,
2002
Unaffiliated revenues $1,029.6 $1,536.8 $379.1 $385.6 $ -- $3,331.1
Intersegment revenues 850.5 0.3 9.0 -- (859.8) --
- ---------------------------- ------------- -------------- ------------- -------------- ------------ ----------------
Total revenues 1,880.1 1,537.1 388.1 385.6 (859.8) 3,331.1
Net income 213.7 68.8 26.6 151.5 -- 460.6
2001
Unaffiliated revenues $ 427.2 $1,624.0 $528.5 $420.3 $ -- $3,000.0
Intersegment revenues 933.9 0.4 5.6 1.9 (941.8) --
- ---------------------------- ------------- -------------- ------------- -------------- ------------ ----------------
Total revenues 1,361.1 1,624.4 534.1 422.2 (941.8) 3,000.0
Cumulative effect of change
in accounting principle -- -- -- 8.5 -- 8.5
Net income 239.7 73.0 29.4 8.9 -- 351.0
Certain prior-period amounts have been reclassified to conform with the current
period's presentation.
16
Financing Activity
Constellation Energy
Constellation Energy issued the following notes during the period from
January 1, 2002 through the date of this report:
Maturity
and
Date Repayment Net
Principal Issued Date Proceeds
- ------------------------ --------- ------ --------- --------
(In millions)
6.35% Fixed Rate Notes $600.0 3/02 4/07 $ 595.4
7.00% Fixed Rate Notes 600.0 3/02 4/12 592.9
7.60% Fixed Rate Notes 600.0 3/02 4/32 592.8
6.125% Fixed Rate Notes 500.0 8/02 9/09 496.1
- ------------------------ --------- ------ -------- ---------
Total $2,300.0 $2,277.2
======================== ========= =========
We used a portion of the net proceeds from the March debt issuances 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). We used a portion of the net
proceeds from the August debt issuance to complete the purchase of NewEnergy.
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 allow issuance 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 allow issuance of commercial paper
after separation. We canceled our plans to separate our businesses in October
2001.
Constellation Energy also has an existing $188.5 million revolving credit
facility available to allow issuance of commercial paper and letters of credit.
This facility expires in June 2003.
These revolving credit facilities allow issuance of letters of credit up to
approximately $1.1 billion. At September 30, 2002, letters of credit that
totaled $296.1 million were issued under all of our facilities.
BGE
In conjunction with the July 1, 2000 transfer of generation assets, BGE
currently is contingently liable for $270 million of the tax exempt debt that
was assigned to nonregulated affiliates of Constellation Energy.
BGE maintains $200 million in annual committed credit facilities, expiring
May through November of 2003, in order to allow commercial paper to be issued.
As of September 30, 2002, BGE had no outstanding commercial paper, which results
in $200.0 million in unused credit facilities.
On August 28, 2002, BGE called $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 were redeemed 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.
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,
o the capacity and transmission rights for the delivery of energy to meet our
physical obligations to our customers, and
o other capital requirements.
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 September 30, 2002, the total amount of commitments was $1,658.5 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
17
approvals, permits, or licenses for new, existing, or 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 or may
require the purchase of emission allowances. 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 July 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 September 30, 2002, we
have spent approximately $22 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.
18
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 require
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 in 1998, 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. There has been no significant
activity with respect to this site since the EPA's Record of Decision in 1998.
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 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 September 30, 2002, BGE has spent approximately $38 million
for remediation at this site.
19
BGE also investigated other small sites where gas was manufactured in the past.
We do not expect the 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 Department of Energy expects that this facility will
open in 2010. However, the opening of Yucca Mountain could be delayed due to
litigation and other issues 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 to the nuclear liability and worker radiation policies that we discuss
below.
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 expired in August 2002. However, 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.
20
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 resulting from a covered loss under the property
policy for Calvert Cliffs or Nine Mile Point. This coverage currently is
purchased through an industry mutual insurance company. If accidents at plants
insured by the mutual insurance company cause a shortfall of funds, 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 for losses resulting from
an accidental outage of a nuclear unit. Coverage begins after a 12-week
deductible period and continues at 100% of the weekly indemnity limit for 52
weeks then 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 could be reduced by up to $98.0 million per unit at Calvert Cliffs
and $82.5 million for Nine Mile Point if an outage of more than one unit is
caused by the same 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
estimate that 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. However, our estimates are based on current
information, and because litigation is ongoing, new events could occur that
could cause these estimates to change.
We signed a settlement agreement unrelated to the refund litigation
regarding our High Desert Power Project with several parties who are also
parties to the refund litigation. Under the settlement agreement, these parties
disclaimed any rights to refunds under this proceeding. However, it is possible
that the FERC could require us to pay refunds to those parties despite the
settlement.
Related Party Transactions - BGE
Income Statement
Under the Restructuring Order issued by the Maryland Public Service Commission
(Maryland PSC) in November 1999, 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 $358.5 million for the quarter ended September 30, 2002
compared to $402.8 million for the same period in 2001 and $872.8 million for
the nine months ended September 30, 2002 compared to $935.3 million for the same
period in 2001.
21
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 entity. These costs were
approximately $7.5 million for the quarter ended September 30, 2002 compared to
$4.0 million for the same period in 2001, and $22.4 million for the nine months
ended September 30, 2002, compared to $14.2 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
$383.7 million at September 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 17, 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 with a gain of
$53.7 million.
We entered into forward starting interest rate swap contracts with notional
amounts that totaled $400 million with an average rate of 5.1% to manage our
interest rate exposure related to the issuance of $500 million of debt in the
third quarter of 2002 as discussed in the Financing Activity section on page 17.
These swap contracts expired in the third quarter of 2002 with a loss of $16.7
million.
We will reclassify these gains and losses from "Accumulated other
comprehensive income" into "Interest expense" and include them in earnings during
the periods in which the hedged interest payments occur. We expect to reclassify
$3.7 million of pre-tax net gains on these swap contracts from "Accumulated
other comprehensive income" into "Interest expense" during the next twelve
months.
Commodity Prices
At September 30, 2002, our merchant energy business had designated certain
fixed-price forward purchase and 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 September 30, 2002, our merchant energy business recorded net unrealized
pre-tax gains of $16.1 million on these hedges, net of associated deferred
income tax effects, in "Accumulated other comprehensive income." We expect to
reclassify $11.1 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 September 30, 2002.
22
However, the actual amount reclassified into earnings could vary from the
amounts recorded at September 30, 2002 due to future changes in market prices.
We recognized into earnings a pre-tax gain of $1.8 million for the quarter and a
pre-tax gain of $0.1 million for the nine months ended September 30, 2002
related to the ineffective portion of our hedges.
Physical Delivery Business
Our merchant energy business focuses on serving the full energy and capacity
requirements of various customers, such as utilities, municipalities,
cooperatives, retail aggregators, and large commercial and industrial customers.
These load-serving activities occur in regional markets in which end use
customer electricity rates have been deregulated and thereby separated from the
cost of generation supply. Our merchant energy business manages these activities
as a physical delivery business rather than a trading 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 was appropriate to apply accrual accounting for these activities.
We describe our accounting for these activities below.
On October 25, 2002, the EITF reached a consensus on Issue 02-3, Recognition
and Reporting of Gains and Losses on Energy Trading Contracts Under EITF Issues
No. 98-10 and No. 00-17. That consensus will affect how we apply the
mark-to-market method of accounting and, among other things, requires us to
begin using the accrual method of accounting for certain existing load-serving
contracts for which we previously were required to apply mark-to-market
accounting. We discuss the impact of the consensus on EITF 02-3 in more detail
in the Accounting Standards Issued section on page 25.
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 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. The consensus on EITF 02-3 requires us to remove
the unamortized balance of these assets and liabilities, excluding the cost of
any acquired contracts, from our Consolidated Balance Sheets no later than
January 1, 2003.
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
mark-to-market 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. Therefore, we
use accrual accounting for New England load-serving transactions and associated
power purchase agreements entered into since the second quarter of 2002.
Because EITF 98-10 significantly limited the circumstances under which
contracts previously designated as a trading activity could be re-designated as
non-trading, prior to the consensus on EITF 02-3, we were required to continue
to include contracts entered into before the second quarter of 2002 in our
mark-to-market accounting portfolio under EITF 98-10. However, the consensus on
EITF 02-3 will affect the accounting for these contracts no later than January
1, 2003 when we will be required to remove these contracts from our
"Mark-to-market energy assets and liabilities" and begin to account for these
contracts under the accrual method of accounting.
23
Long-Term Power Sales Contracts
We entered into long-term power sales contracts in connection with our
non-trading load-serving activities. We also entered into long-term power sales
contracts associated with certain of our power plants. Our non-trading
load-serving power sales contracts extend for terms through 2007 and provide for
the sale of full requirements energy to electricity distribution companies and
certain retail customers. Our power sales contracts associated with our power
plants extend for terms into 2011 and provide for the sale of all or a portion
of the actual output of certain of our power plants. All long-term contracts
were executed at pricing that approximated market rates, including profit
margin, at the time of execution. We recognize revenue on non-trading long-term
power sales contracts on the accrual basis. We recognize the fixed price portion
of such contracts, representing capacity payments, on a monthly basis as the
payment is earned. We recognize the variable price portion of such contracts in
accordance with the contract price as power is delivered.
Fuel and Purchased Energy Costs
We assemble a variety of power supply resources, including baseload,
intermediate, and peaking plants that we own, as well as a variety of power
supply contracts that may have similar characteristics, in order to enable us to
meet our customers' energy requirements, which vary on an hourly basis. We
purchase power when our load-serving requirements exceed the amount of power
available from our supply resources or when it is more economic to do so than to
operate our power plants. The amount of power purchased depends on a number of
factors, including the capacity and availability of our power plants, the level
of customer demand, and the relative economics of generating power versus
purchasing power from the spot market.
We include all of our accrual-basis third-party fuel and purchased power
costs in "Operating expenses" in our Consolidated Statements of Income. These
costs were as follows:
Quarter Ended Nine Months Ended
September 30, September 30,
2002 2001 2002 2001
- -------------------------------------------------------------
(In millions)
Fuel and Purchased Energy $314.2 $176.3 $647.0 $391.5
Accounting Standards Issued
SFAS No. 143
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 requires
a cumulative effect of a change in accounting principle to be reported upon
initial adoption and is effective for fiscal years beginning after June 15,
2002, with early adoption permitted. Our preliminary calculations indicate that
we expect to recognize a net after-tax gain of approximately $140 million upon
the adoption of this statement.
Substantially all of this preliminary net gain relates to the impact of
adopting SFAS No. 143 on the measurement of the liability for the
decommissioning of our Calvert Cliffs nuclear power plant. Expected losses on
the adoption of SFAS No. 143 in other areas of our business are expected to be
offset by the estimated gain relating to the decommissioning of our Nine Mile
Point nuclear power plant. The Calvert Cliffs' gain is primarily due to using a
longer discount period as a result of license extension. The gain also is
significantly impacted by the level of the credit-adjusted interest rate used to
discount the cash flows associated with decommissioning the plant. The existing
liability for the decommissioning of Calvert Cliffs was determined in accordance
with ratemaking treatment established by the Maryland Public Service Commission
and is based on a previous decommissioning cost estimate that contemplated
decommissioning being completed at a point in time much closer to the expiration
of the plant's original operating license.
The actual impact of adopting SFAS No. 143 will be based on applying the
appropriate credit-adjusted, risk free interest rates as of the date of adoption
to our final estimates of the cash flows, which are still being refined,
associated with our legal obligations to retire long-lived assets. Our expected
$140 million net after-tax gain is based on the level of interest rates as of
October 25, 2002. If interest rates change between that date and the date of
adoption, it could have a material impact on the ultimate net gain to be
recorded upon the adoption of SFAS No. 143. We estimate that a one-percentage
point decrease in the credit-adjusted risk free rate would reduce our expected
net gain by approximately $28 million after-tax.
We do not expect the adoption of SFAS No. 143 to have a material impact on
the financial results of BGE.
24
SFAS No. 146
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.
We will reflect the requirements of this statement in any exit or disposal
initiatives after its effective date.
EITF 02-3
On October 25, 2002, the EITF reached a consensus on Issue 02-3 that changes
the accounting for certain energy contracts. The main provisions of Issue 02-3
are as follows:
o The EITF rescinded Issue 98-10. As a result, this new consensus prohibits
mark-to-market accounting for energy-related contracts that do not meet
the definition of a derivative under SFAS No. 133. Any contracts subject
to the consensus must be accounted for on the accrual basis upon
application of the consensus. Entities are encouraged to reclassify prior
period net gains and losses on these contracts to a gross presentation if
appropriate under applicable accounting literature.
o The consensus applies immediately to non-derivative energy-related contracts
executed after October 25, 2002.
o The consensus applies to existing non-derivative energy-related contracts for
fiscal periods beginning after December 15, 2002 (unless applied earlier)
and the cumulative effect of a change in accounting principle must be reported
upon initial application.
o The EITF minutes on Issue 02-3 indicate that an entity should not record
unrealized gains or losses at the inception of derivative contracts
unless the fair value of each contract in its entirety is evidenced by
quoted market prices or other current market transactions for contracts
with similar terms and counterparties.
o The EITF reaffirmed its June consensus requiring gains and losses on
derivative energy trading contracts (whether realized or unrealized) to
be reported as revenue on a net basis in the income statement.
The EITF deliberations and consensus on Issue 02-3 will not affect our cash
flows or our accounting for new load-serving contracts for which we have been using
accrual accounting since early 2002. Additionally, we must continue to mark existing
non-derivative energy-related contracts to market prior to applying the consensus.
However, the consensus requires us to record a non-cash, cumulative effect adjustment
to convert these non-derivative mark-to-market contracts to accrual accounting no
later than January 1, 2003.
We have not identified the individual contracts to which the consensus applies,
and the level of market prices at the date of application will affect the amount
of the required cumulative effect adjustment we must record at that time. As a
result, we cannot predict the impact of initially applying the consensus to
existing contracts, but the non-cash, one-time cumulative effect adjustment
required under Issue 02-3 could be material to, and could reduce, "Net income,"
"Mark-to-market energy assets and liabilities," and "Common shareholders'
equity."
We are reviewing our existing portfolio of mark-to-market contracts to
identify the contracts that are subject to the requirements of this consensus.
The primary contracts that we expect will be affected are our full requirements
load-serving contracts and unit-contingent power purchase contracts, the
majority of which are in New England and Texas and were entered into prior to
the shift to accrual accounting earlier in 2002 as discussed in the Physical
Delivery Business section on page 23. Additionally, we are reviewing derivatives
we used as supply sources and hedges of contracts that are subject to this
consensus. To the extent permitted by SFAS No. 133, we will designate derivative
contracts used to fulfill our load-serving contracts as either normal purchases
or cash flow hedges under SFAS No. 133 effective at the time we apply the
consensus.
We cannot predict the impact of applying the ongoing provisions of Issue
02-3. Those provisions prohibit mark-to-market accounting for gains at inception
of new non-derivative energy contracts, require accrual accounting for those
contracts, and limit the ability to record gains at the inception of new
derivative contracts. We believe that our shift to accrual accounting for new
physical delivery transactions since early 2002 is consistent with the requirement
of EITF 02-3 to use accrual accounting for non-derivative contracts. However, the
ultimate impact of applying the consensus will be affected by many factors, including:
o the specific contracts to which the consensus applies,
o the timing and amount of cash flows under those contracts,
o our ability to designate and qualify related derivative contracts for normal
purchase and sale accounting or hedge accounting under SFAS No. 133,
25
o our ability to enter into new mark-to-market derivative origination
transactions, and
o sufficient liquidity and transparency in the energy markets to permit us to
record gains at inception of new derivative contracts because fair value
is evidenced by quoted market prices or current market transactions.
While we cannot predict the ongoing impact of applying the consensus, we
expect that our reported earnings for contracts subject to the consensus will
generally match the cash flows from those contracts more closely and may be less
volatile under accrual accounting than under mark-to-market accounting, which
reflects changes in fair value of contracts when they occur rather than when
products are delivered and costs are incurred. Alternatively, other
comprehensive income may have greater fluctuations after we apply the consensus
because of a larger number of derivative contracts that we may designate for
hedge accounting under SFAS No. 133, but these fluctuations will not affect
earnings or cash flows. Additionally, because we will record revenues and costs
on a gross basis under accrual accounting, our revenues and costs could
increase, but our earnings will not be affected by gross versus net reporting.
Earnings Per Share
Basic earnings per common share (EPS) is computed by dividing earnings
applicable to common stock by the weighted-average number of common shares
outstanding for the period. Diluted EPS reflects the potential dilution of
common stock equivalent shares that could occur if securities or other contracts
to issue common stock were exercised or converted into common stock. Our
dilutive common stock equivalent shares consist of stock options. Stock options
to purchase approximately 4.7 million shares during the quarter and
approximately 2.1 million shares for the nine months ended September 30, 2002
were not dilutive and were excluded from the computation of diluted EPS for
these periods. Stock options to purchase approximately 1.9 million shares during
the quarter ended September 30, 2001 were not dilutive and were excluded from
the computation of diluted EPS for that period. For the nine months ended
September 30, 2001, all stock options were dilutive and were included in the
calculation of diluted EPS, but the effect of that dilution was not significant
enough to result in a change in the EPS presented in our Consolidated Statements
of Income.
26
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 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 customers' needs throughout
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 15.
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.
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
38.
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 (such as load-serving, tolling
contracts, and power purchase agreements), 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 (until October 25, 2002), and
o interests in international 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 58, 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 included
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 September 2002, we announced the closing of BGE
Home's retail merchandise stores by December 2002 and in October 2002, we sold
all of our senior-living facilities.
In this discussion and analysis, we explain the general financial condition
and the results of operations for Constellation Energy and BGE including:
o factors which affect our businesses,
o our earnings and costs in the periods presented,
o changes in earnings and costs between periods,
o sources of earnings,
o impact of these factors on our overall financial condition,
o expected future expenditures for capital projects, and
o expected sources of cash for future capital expenditures.
As you read this discussion and analysis, refer to our Consolidated
Statements of Income on page 3, which present the results of our operations for
the quarters and nine months ended September 30, 2002 and 2001. We analyze and
explain the differences between periods in the specific line items of the
Consolidated Statements of Income.
27
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
On October 25, 2002, the Emerging Issues Task Force (EITF) reached a consensus
on Issue 02-3, Recognition and Reporting of Gains and Losses on Energy Trading
Contracts Under EITF Issues No. 98-10 and No. 00-17. That consensus will affect
how we apply the mark-to-market method of accounting. We describe our
application of the mark-to-market method of accounting prior to October 25, 2002
below, and we discuss the impact of the consensus on EITF 02-3 on page 29.
Prior to EITF 02-3
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 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, including physical delivery transactions in Texas and New
England as described in the Physical Delivery Business section on page 51. We
also designate certain fixed-price forward purchase and sale 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 section on page 22.
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 that are not incorporated in market price information or other
market-based estimates used to determine fair value of our mark-to-market energy
contracts. To the extent possible, we utilize market-based data together with
quantitative methods for both measuring the risks for which we record reserves
and determining the level of such reserves and changes in those levels.
We describe below the main types of reserves we record and the process for
establishing each. Generally, increases in reserves reduce our earnings, and
decreases in reserves increase our earnings. However, all or a portion of the
effect on earnings of changes in reserves may be offset by changes in the value
of the underlying positions.
o Close-out reserve - this reserve represents the estimated cost to close out
or sell to a third- party open mark-to-market positions. This reserve has
the effect of valuing "long" positions at the bid price and "short"
positions at the offer price. We compute this reserve based on our
estimate of the bid/offer spread for each commodity and option price and
the absolute quantity of our open positions for each year. Effective July 1,
2002, based on the ongoing EITF 02-3 deliberations, to the extent that we
are not able to obtain market information for similar contracts, we base
the close-out reserve on the initial contract margin,
28
thereby recording no gain or loss at inception. The level of this reserve
increases as we have larger unhedged positions, bid-offer spreads increase,
or market information is not available, and it decreases as we reduce our
unhedged positions, bid-offer spreads decrease, or market information becomes
available.
o Credit-spread adjustment - for risk management purposes, we compute the
value of our mark-to-market assets and liabilities using a risk-free
discount rate. In order to compute fair value for financial reporting
purposes, we adjust the value of our mark-to-market assets to reflect the
credit-worthiness of each individual counterparty based upon published
credit ratings, where available, or equivalent internal credit ratings
and associated default percentages. We compute this reserve by applying
the appropriate default percentage to our outstanding credit exposure,
net of collateral, for each counterparty. The level of this reserve
increases as our credit exposure to counterparties increases, the
maturity terms of our transactions increase, or the credit ratings of our
counterparties deteriorate, and it decreases when our credit exposure to
counterparties decreases, the maturity terms of our transactions
decrease, or the credit ratings of our counterparties improve.
Mark-to-market 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.
EITF 02-3
On October 25, 2002, the EITF reached a consensus on Issue 02-3 that changes the
accounting for certain energy contracts. The main provisions of Issue 02-3 are
as follows:
o The EITF rescinded Issue 98-10. As a result, this new consensus prohibits
mark-to-market accounting for energy-related contracts that do not meet
the definition of a derivative under SFAS No. 133. Any contracts subject
to the consensus must be accounted for on the accrual basis upon
application of the consensus. Entities are encouraged to reclassify prior
period net gains and losses on these contracts to a gross presentation if
appropriate under applicable accounting literature.
o The consensus applies immediately to non-derivative energy-related contracts
executed after October 25, 2002.
o The consensus applies to existing non-derivative energy-related contracts
for fiscal periods beginning after December 15, 2002 (unless applied earlier)
and the cumulative effect of a change in accounting principle must be reported
upon initial application.
o The EITF minutes on Issue 02-3 indicate that an entity should not record
unrealized gains or losses at the inception of derivative contracts
unless the fair value of each contract in its entirety is evidenced by
quoted market prices or other current market transactions for contracts
with similar terms and counterparties.
o The EITF reaffirmed its June consensus requiring gains and losses on
derivative energy trading contracts (whether realized or unrealized) to
be reported as revenue on a net basis in the income statement.
The EITF deliberations and consensus on Issue 02-3 will not affect our cash
flows or our accounting for new load-serving contracts for which we have been using
accrual accounting since early 2002. Additionally, we must continue to mark
existing non-derivative energy-related contracts to market prior to applying the
consensus. However, the consensus requires us to record a non-cash, cumulative
effect adjustment to convert these non-derivative mark-to-market contracts to
accrual accounting no later than January 1, 2003.
29
We have not identified the individual contracts to which the consensus applies,
and the level of market prices at the date of application will affect the amount
of the required cumulative effect adjustment we must record at that time. As a
result, we cannot predict the impact of initially applying the consensus to
existing contracts, but the non-cash one-time cumulative effect adjustment
required under Issue 02-3 could be material to, and could reduce, "Net income,"
"Mark-to-market energy assets and liabilities," and "Common shareholders'
equity."
We are reviewing our existing portfolio of mark-to-market contracts to
identify the contracts that are subject to the requirements of this consensus.
The primary contracts that we expect will be affected are our full requirements
load-serving contracts and unit-contingent power purchase contracts, the
majority of which are in Texas and New England and were entered into prior to
the shift to accrual accounting earlier in 2002 as discussed in the Physical
Delivery Business section on page 51. Additionally, we are reviewing derivatives
we used as supply sources and hedges of contracts that are subject to this
consensus. To the extent permitted by SFAS No. 133, we will designate derivative
contracts used to fulfill our load-serving contracts as either normal purchases
or cash flow hedges under SFAS No. 133 effective at the time we apply the
consensus.
We cannot predict the impact of applying the ongoing provisions of Issue
02-3. Those provisions prohibit mark-to-market accounting for gains at inception
of new non-derivative energy contracts, require accrual accounting for those
contracts, and limit the ability to record gains at the inception of new
derivative contracts. We believe that our shift to accrual accounting for new
physical delivery transactions since early 2002 is consistent with the requirement
of EITF 02-3 to use accrual accounting for non-derivative contracts. However, the
ultimate impact of applying the consensus will be affected by many factors, including:
o the specific contracts to which the consensus applies,
o the timing and amount of cash flows under those contracts,
o our ability to designate and qualify related derivative contracts for normal
purchase and sale accounting or hedge accounting under SFAS No. 133,
o our ability to enter into new mark-to-market derivative origination transactions,
and
o sufficient liquidity and transparency in the energy markets to permit us to
record gains at inception of new derivative contracts because fair value
is evidenced by quoted market prices or current market transactions.
While we cannot predict the ongoing impact of applying the consensus, we
expect that our reported earnings for contracts subject to the consensus will
generally match the cash flows from those contracts more closely and may be less
volatile under accrual accounting than under mark-to-market accounting, which
reflects changes in fair value of contracts when they occur rather than when
products are delivered and costs are incurred. Alternatively, other
comprehensive income may have greater fluctuations after we apply the consensus
because of a larger number of derivative contracts that we may designate for
hedge accounting under SFAS No. 133, but these fluctuations will not affect
earnings or cash flows. Additionally, because we will record revenues and costs
on a gross basis under accrual accounting, our revenues and costs could
increase, but our earnings will not be affected by gross versus net reporting.
Effective July 1, 2002, we applied the guidance prohibiting the recording of
gains or losses at inception on derivative contracts for which fair value is
determined in a manner other than by using current market prices. Prior to that
time, we recorded all mark-to-market energy contracts at fair value at inception
based upon available market information or, in the absence of such information,
management's best estimates. However, after review of the deliberations of the
EITF regarding Issue 02-3, we adopted this guidance for new transactions.
To the extent that we are not able to observe quoted market prices or other
current market transactions for contract values determined using models, we
record a reserve to adjust such contracts to result in zero gain or loss at
inception. We remove the reserve and record such contracts at fair value when we
obtain current market information for contracts with similar terms and
counterparties. Contracts affected by this treatment are those for commodities
or terms for which a liquid market does not exist or is not frequently traded.
The June 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 did 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. When we apply EITF 02-3, this provision will only affect
derivative trading contracts, and as provided in the consensus, we will review
non-derivative transactions for possible reclassification of prior period net
gains and losses to a gross presentation if appropriate under applicable
accounting literature.
We discuss the impact of mark-to-market accounting on our financial results
in the Results of Operations -- Merchant Energy Business section on page 43.
30
Evaluation of Assets for Impairment and Other Than Temporary Decline in Value
We are required to evaluate certain assets that have long lives (for example,
generating property and equipment and real estate) to determine if they are
impaired when certain conditions exist. SFAS No. 144, Accounting for the
Impairment or Disposal of Long-Lived Assets, provides the accounting for
impairments of long-lived assets. We are required to test our long-lived assets
for recoverability whenever events or changes in circumstances indicate that
their carrying amount may not be recoverable. Examples of such events or changes
would be as follows:
o a significant decrease in the market price of a long-lived asset,
o a significant adverse change in the manner an asset is being used or its
physical condition,
o an adverse action by a regulator or in the business climate,
o an accumulation of costs significantly in excess of the amount originally
expected for the construction or acquisition of an asset,
o a current-period loss combined with a history of losses or the projection of
future losses, or
o a change in our intent about an asset from an intent to hold to a greater
than 50% likelihood that an asset will be sold or disposed of before the
end of its previously estimated useful life.
For long-lived assets that are expected to be held and used, SFAS No. 144
requires that an impairment loss shall only be recognized if the carrying amount
of an asset is not recoverable and exceeds its fair value. The carrying amount
of an asset is not recoverable under SFAS No. 144 if the carrying amount exceeds
the sum of the undiscounted future cash flows expected to result from the use
and eventual disposition of the asset. Therefore, when we believe an impairment
condition may have occurred, we are required to estimate the undiscounted future
cash flows associated with a long-lived asset or group of long-lived assets.
This necessarily involves judgement surrounding the inherent uncertainty of
future cash flows. In order to estimate an asset's future cash flows, we will
consider historical cash flows, as well as reflect our understanding of the
extent to which future cash flows will be either similar to or different from
past experience based on all available evidence. To the extent applicable, the
assumptions we use are consistent with forecasts that we are otherwise required
to make (for example, in preparing our other earnings forecasts). If we are
considering alternative courses of action to recover the carrying amount of a
long-lived asset (such as the potential sale of an asset), we probability-weight
the alternative courses of action to establish the cash flows.
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
the assumptions used in our estimates, and the impact of such variations could
be material.
For long-lived assets that can be classified as assets to be disposed of by
sale under SFAS No. 144, an impairment loss shall be recognized to the extent
their carrying amount exceeds their fair value, including costs to sell.
The estimation of fair value under SFAS No. 144, whether in conjunction with
an asset to be held and used or with an asset to be disposed of by sale, also
involves estimation and judgment. We consider quoted market prices in active
markets to the extent they are available. In the absence of such information, we
may look to prices of similar assets, consult with brokers, or employ other
valuation techniques. Often, we will discount the estimated future cash flows
associated with the asset using a single interest rate that is commensurate with
the risk involved with such an investment or employ an expected present value
method that probability-weights a range of possible outcomes. The use of these
methods involves the same inherent uncertainty of future cash flows as discussed
above with respect to undiscounted cash flows and actual future market prices
and project costs could vary from those used in our estimates, and the impact of
such variations could be material.
We are also required to evaluate our equity-method and cost-method
investments (for example, in partnerships that own power projects) to determine
whether or not they are impaired. Accounting Principles Board Opinion (APB) No.
18, The Equity Method of Accounting for Investments in Common Stock, provides
the accounting for these investments. The standard for determining whether an
impairment must be recorded under APB No. 18 is whether the investment has
experienced a loss in value that is considered an "other than a temporary"
decline in value.
The evaluation and measurement of impairments under the APB No. 18 standard
involves the same uncertainties as described above for long-lived assets that we
own directly and account for in accordance with SFAS No. 144. Similarly, the
estimates that we make with respect to our equity and cost-method investments
are subject to variation, and the impact of such variations could be material.
Additionally, if the projects in which we hold these investments recognize an
impairment under the provisions of SFAS No. 144, we would record our
proportionate share of that impairment loss and would evaluate our investment
for an other than temporary decline in value under APB No. 18.
31
Events of 2002
Impairment Losses and Other Costs
Investments in Qualifying Facilities and Power Projects
As discussed in the Notes to Consolidated Financial Statements on page 12, our
merchant energy business recorded impairment losses on certain of these
investments totaling $14.4 million pre-tax, or $9.9 million after-tax, under the
provisions of APB No. 18. At September 30, 2002, our investment in these
projects consisted of the following:
Book Value Book Value
Before Pre-tax After-tax After
Project Type Write-down Write-down Write-down Write-down
- -------------------------------------------------------------------
(In millions)
Geothermal $151.4 $ 5.2 $3.4 $146.2
Coal 138.6 -- -- 138.6
Hydroelectric 63.0 -- -- 63.0
Biomass 55.6 -- -- 55.6
Fuel Processing 27.1 2.6 1.7 24.5
Solar 10.5 -- -- 10.5
Waste to Energy 6.6 6.6 4.8 --
- -------------------------------------------------------------------
Total $452.8 $14.4 $9.9 $438.4
===================================================================
The provisions of APB No. 18 require that an impairment loss be recognized
when an investment experiences a loss in value that is other than temporary as
discussed in our Application of Critical Accounting Policies section on page 28.
During the third quarter of 2002, we performed an analysis of whether any of the
investments were impaired.
As a result of our analysis, we concluded that the declines in value of
particular investments in certain qualifying facilities and power projects were
other than temporary in nature under the provisions of APB No. 18 and we
recognized the following losses in the third quarter of 2002:
o We recognized a $5.2 million pre-tax, or $3.4 million after-tax, other than
temporary decline in value of our investment in a partnership that owns a
geothermal project in Nevada. This project experienced a well implosion
and we believe that the expected cash flows from the project will not be
sufficient to recover our equity interest in that partnership.
o We recognized a $2.6 million pre-tax, or $1.7 million after-tax, other than
temporary decline in value of our investment in a fuel processing site in
Pennsylvania where the expected cash flows from a sublease are no longer
expected to be sufficient to recover our lease costs associated with this
site.
o We recognized a $6.6 million pre-tax, or $4.8 million after-tax, other than
temporary decline in value of our investment in a partnership that owns a
waste burning power project in Michigan.
We believe the current market conditions for our equity-method investments
that own geothermal, coal, hydroelectric, and fuel processing projects provide
sufficient positive cash flows to recover our investments. We continuously
monitor issues that potentially could impact future profitability of these
investments, including environmental and legislative initiatives. We discuss
certain risks and uncertainties in more detail in our Forward Looking Statements
section on page 67. However, should future events cause these investments to
become uneconomic, our investments in these projects could become impaired under
the provisions of APB No. 18.
We have an investment in a partnership that owns a geothermal project with a
book value of $93 million. Currently, the project is not generating at its
designed capacity. The project is drilling wells at this site to restore the
generation to its capacity. We expect the current well drilling to be successful
and the geothermal resource to be sufficient to enable the project to generate
adequate cash flows over the life of this project to recover our equity interest
in that investment. However, should current or future well drilling at this site
prove to be unsuccessful or become uneconomic causing us not to make future
investments in this partnership, our investment in this partnership could become
impaired under the provisions of APB No. 18.
The ability to recover our costs in our equity-method investments that own
biomass and solar projects is partially dependent upon subsidies from the State
of California. Under the California Public Utility Act, subsidies currently
exist in that the California Public Utilities Commission (CPUC) requires
electric corporations to identify a separate rate component to fund the
development of renewable resources technologies, including solar, biomass, and
wind facilities. In addition, proposed legislation requires that each electric
corporation increase its total procurement of eligible renewable energy
resources by at least one percent per year so that 20% of its retail sales are
procured from eligible renewable energy resources by 2017. The proposed
legislation also requires the California Energy Commission to award supplemental
energy payments to electric corporations to cover above market costs of
renewable energy.
Given the need for electric power and the desire for renewable resource
technologies, we believe California will continue to subsidize the use of
renewable energy to make these projects economical to operate. However, should
the California legislation fail to adequately support the renewable energy
initiatives, our equity-method investments in these types of projects could
become impaired under the provisions of APB No. 18, and any losses recognized
could be material.
32
If our strategy were to change from an intent to hold to an intent to sell
for any of our equity-method investments in qualifying facilities or power
projects, we would need to adjust their book value to fair value, and that
adjustment could be material. If we were to sell these investments in the
current market, we may have losses that could be material.
Loss on Sale of Steam Turbine
As discussed in Note 2 of our 2001 Annual Report on Form 10-K, we recognized a
$30 million impairment loss on four turbines, associated with a discontinued
development program. 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.
Closing of BGE Home Retail Merchandise Stores
In September 2002, we announced our decision to close our BGE Home retail
merchandise stores. In connection with that decision, we recognized
approximately $9.3 million in exit costs. We recognized $2.7 million related to
expected severance costs for 115 employees and $2.5 million of costs in
connection with the termination of leases for the eight stores in accordance
with 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 also recognized $3.2 million for the write-off of unamortized leasehold
improvements in accordance with SFAS No. 144, and $0.9 million for the
write-down of inventory to a lower-of-cost-or-market valuation in accordance
with Accounting Research Bulletin No. 43, Restatement and Revision of Accounting
Research Bulletins. The $0.9 million is included in "Operating expenses" in our
Consolidated Statements of Income.
Real Estate and International Investments
As discussed in our 2001 Annual Report on Form 10-K, we changed our strategy
from an intent to hold to an intent to sell for certain of our non-core assets.
During the third quarter of 2002, we determined that the fair value of several
real estate projects and our investment in an international power project
declined below their respective book values due to deteriorating market
conditions for these projects. Accordingly, we recorded losses that totaled $1.8
million for these projects in accordance with SFAS No. 144 and APB No. 18.
Sale of Senior-Living Facilities
On October 25, 2002, we sold all of our 18 senior-living facilities for $77.2
million that represents a combination of cash and the assumption by the buyer of
existing mortgages. The proceeds from the sale approximate the book value of
these facilities.
Workforce Reduction Costs
During 2002, we incurred costs related to workforce reduction efforts initiated
in the fourth quarter of 2001 and additional initiatives undertaken in the third
quarter of 2002. We discuss these costs in more detail below.
2001 Programs
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, we recorded $35.1 million of net workforce
reduction costs associated with our workforce initiatives. In the first quarter
of 2002, 308 employees elected the age 50 to 54 Voluntary Special Early
Retirement Program (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
$25.1 million 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 recognized as
expense, of which BGE recognized $20.9 million. The remaining $9.2 million was
recognized by BGE as a regulatory asset related to its gas business.
In the second quarter of 2002, we recorded $16.3 million of net workforce
reduction costs. This amount included 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 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.
33
The $16.3 million of net workforce reduction costs recorded in the second
quarter of 2002 as discussed above, consisted of $13.3 million recognized as
expense, of which BGE recognized $7.9 million. The remaining $3.0 million was
recognized by BGE as a regulatory asset related to its gas business.
In the third quarter of 2002, we recorded $6.0 million of additional costs
associated with our 2001 workforce reduction initiatives. This amount consisted
of a $5.2 million settlement charge for our basic, qualified pension plan under
SFAS No. 88 for additional lump-sum pension payments made during the period, and
an $0.8 million expense associated with deferred payments to employees eligible
for the VSERP.
The $6.0 million discussed above, included $5.3 million recognized as
expense, of which BGE recognized $3.3 million. The remaining $0.7 million was
recognized by BGE as a regulatory asset related to its gas business.
2002 Programs
In the third quarter of 2002, we recorded approximately $7.2 million of
workforce reduction costs associated with new initiatives expected to result in
the elimination of 118 positions at Calvert Cliffs Nuclear Power Plant (Calvert
Cliffs) and in our information technology organization. In accordance with EITF
94-3, we recognized a $7.2 million charge to expense for anticipated involuntary
severance costs associated with these workforce reductions. BGE recorded $0.6
million of this amount associated with the information technology organization.
In addition, we recorded $2.7 million of workforce reduction costs for the
elimination of 115 positions as a result of the closing of our BGE Home retail
merchandise stores. These costs are included in "Impairment losses and other
costs" in our Consolidated Statements of Income. We discuss the closing of these
stores in more detail on page 33.
Ongoing Impacts
In the fourth quarter of 2002, we expect to record approximately $2 million of
additional costs associated with the 2001 workforce reduction initiatives. We
also expect to incur an additional $5 million in SFAS No. 88 settlement charge
in the fourth quarter 2002 as a result of lump-sum pension payments under our
non-qualified pension plan.
Once our workforce reduction efforts to date have been fully implemented, we
expect ongoing, full year labor cost savings of approximately $80 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.
Acquisition of NewEnergy
On September 9, 2002, we completed our purchase of AES NewEnergy, Inc. from AES
Corporation. Subsequent to the acquisition, we renamed AES NewEnergy, Inc. as
Constellation NewEnergy, Inc. (NewEnergy). NewEnergy is a leading national
provider of electricity, natural gas, and energy services, serving approximately
4,300 megawatts (MW) of load associated with large commercial and industrial
customers in competitive energy markets including the Northeast, Mid-Atlantic,
Midwest, Texas and California. We acquired 100% ownership of NewEnergy for cash
of $253.3 million including $1.4 million of direct costs associated with the
acquisition. We acquired cash of $45.5 million as part of the purchase. We
describe the net assets acquired in the Notes to Consolidated Financial
Statements on page 14.
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 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.
34
The new contract is a "tolling" structure, which provides CDWR the right,
but not the obligation, to purchase power from the High Desert Power Project 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 proposed interpretation, we may
be required to consolidate the SPE in our Consolidated Balance Sheets. We would
have recorded approximately $434.5 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 September 30, 2002. As currently drafted, the proposed interpretation would
be applied as of the beginning of the first fiscal period beginning after March
15, 2003.
We discuss our High Desert project in more detail in the Capital Resources
section on page 61.
Generating Facilities Commence Operations
The following generating facilities commenced operations beginning in the second
and third quarters of 2002. Our origination and risk management operation
manages the output of these plants.
Capacity Primary
Plant Location (MW) Type Fuel
- ---------------- ------------- -------- ------------ --------
Combined Natural
Rio Nogales Seguin, TX 800 Cycle Gas
Combustion Natural
Oleander Brevard Co., FL 680 Turbine Gas
Combined Natural
Holland Energy Shelby Co., IL 665 Cycle Gas
As discussed in our Re-designation of Texas Business section on page 51, 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 has contracts to sell 75% of its output under a tolling
contract to Seminole Electric Cooperative of Tampa, Florida for seven years. The
contract for 50% of the output begins in December 2002, while the contract for
the other 25% begins in May 2003. Additionally, Oleander has signed two tolling
contracts 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 May 2003. The
second contract for the remaining 25% of the output not sold to Seminole
Electric Cooperative runs through May 2005 and can be extended by either Florida
Power and Light Company or Oleander for two years at predetermined prices.
The output from the Holland Energy project, along with power purchase
agreements, is used to meet our customers' energy requirements in the
mid-continent region.
We have one remaining generating facility under construction. We expect our
High Desert plant in Victorville, CA, a 750 MW gas combined cycle facility, to
be operational in 2003.
Pension Plan Assets
As a result of declines in the financial markets, our actual return on pension
plan assets was a loss of approximately 10% for the nine months ended September
30, 2002. If our return on pension plan assets remains unchanged through the end
of 2002 and interest rates remain at current levels, we expect to record an
after-tax charge to equity of approximately $100 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 that
depends on the performance of the financial markets, and our discount rate
assumption that depends on year-end interest rates. As a result, the charge to
equity could change materially.
We contributed $80 million, or $50 million after-tax, to our pension plan in
2002. We expect to contribute an additional $60 to $70 million after-tax in
2003.
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 17. 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.
In August 2002, we issued $500 million of debt as discussed in the Notes to
Consolidated Financial Statements - Financing Activity section on page 17. A
portion of the proceeds was used for the acquisition of NewEnergy.
35
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.
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.
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.
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 $2.8 million for consulting
services provided to Constellation Energy during the nine months ended September
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, which
continued to provide legal services to the Company during that period.
36
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.
We are pursuing an integrated energy platform that provides a balanced mix
of stable and predictable earnings from regulated utility operations with a
growth platform from merchant energy operations. The strategy for our merchant
energy business is to be a leading competitive provider of energy solutions for
large 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 customers' needs throughout North America.
The integration of electric generation assets with power marketing and risk
management of energy and energy-related commodities allows our merchant energy
business to maximize value across energy products, over geographic regions, and
over time. Our focus is on providing solutions to customers' energy needs and
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 provides service to large customers
with approximately 18,000 megawatts of peak load in the aggregate. Our merchant
energy business owns approximately 11,300 megawatts of generation capacity. We
also have a 750 MW natural gas-fired combined cycle production facility under
construction in California.
To achieve our strategic objectives, we expect to continue to pursue
opportunities that expand our access to customers and 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 large
customers and by acquiring and developing additional generating facilities when
desirable to support our merchant energy business.
Our merchant energy business will focus on long-term, high-value sales of
energy, capacity, and related products to large customers, including
distribution companies, industrial customers, and large commercial customers
primarily in the regional markets in which end-use customer electricity rates
have been deregulated and thereby separated from the cost of generation supply.
These markets include the New England region, the New York region, the
Mid-Atlantic region, Texas, Illinois, California, and certain areas in Canada.
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.
Beginning 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.
37
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
67.
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 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 trading practices
designed to manipulate market prices. In addition, several merchant energy
businesses significantly reduced their energy trading activities due to
deteriorating credit quality.
Beginning in the second quarter of 2002, 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 positions to reflect
the underlying liquidity of the various regional energy markets. As a result of
these actions, Constellation Power Source's average value-at-risk declined to $9
million during the third quarter of 2002 and was $7 million as of November 8,
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 September 30, 2002, approximately 83% of our credit portfolio was
rated at least investment grade by the major rating agencies, with 4% rated
below investment grade and 13% not rated. Of the 13% not rated, 83% 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 37. We discuss our liquidity in the
Financial Condition section on page 59.
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
38
Source to supply 90% and Allegheny Energy Supply Company, LLC (Allegheny) to
supply the remaining 10% of BGE's standard offer service for the final three
years (July 1, 2003 to June 30, 2006) of the transition period. Recently, the
credit ratings of Allegheny were downgraded to below investment grade. Under the
terms of the contract, in certain circumstances, BGE has the right to request
additional credit support from Allegheny to secure performance under the
contract. If BGE was to exercise these rights and Allegheny did not meet such
request, BGE could liquidate and terminate the contract. As of the date of this
report, Allegheny is in compliance with the terms of the contract.
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 and its proposal
released in July 2002 on a standard market design could provide our merchant
energy business other opportunities as discussed in the FERC
Regulation--Regional Transmission Organizations and Standard Market Design
section on page 40.
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 46. 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 estimate that 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. However, our estimates are based on
current information and because litigation is ongoing, new events could occur
that could cause the actual amount, if any, to be different from our estimate.
We signed a settlement agreement unrelated to the refund litigation
regarding our High Desert Power Project with several parties who are also
parties to the refund litigation. Under the settlement agreement, these parties
disclaimed any rights to refunds under this proceeding. However, it is possible
that the FERC could require us to pay refunds to those parties despite the settlement.
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 electric 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.
39
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.
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 57.
FERC Regulation
Regional Transmission Organizations and Standard Market Design
In December 1999, FERC issued Order 2000, amending its regulations under the
Federal Power Act to advance the formation of Regional Transmission
Organizations (RTOs) that would allow easier access to transmission.
On July 31, 2002 the FERC issued a proposed rulemaking regarding
implementation of a standard market design (SMD) for wholesale electric markets.
The SMD rulemaking is intended to be complimentary to FERC's RTO order, and will
require RTOs to substantially comply with its provisions. The SMD proposals
require transmission providers to turn over the operation of their facilities to
an independent operator that will operate them consistent with a revised market
structure proposed by the FERC. According to the FERC, the revised market
structure will reduce inefficiencies caused by inconsistent market rules and
barriers to transmission access. The FERC proposed that its rule be implemented
in stages by October 1, 2004. Comments on the SMD proposal must be submitted by
January 2003.
We believe that the SMD proposal may lead to long-term benefits for
Constellation Energy and BGE in regions where it is implemented. However, until
the proposal is finalized, we cannot predict its effect on our, or BGE's,
financial results.
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 22 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.
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
57.
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.
40
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
nine months ended September 30, 2002 and 2001, and the percentage change in the
number of degree-days between these periods in the following table:
Quarter Ended Nine Months Ended
September 30 September 30
2002 2001 2002 2001
- ----------------------------------------------------------
Heating degree-days 59 136 2,675 3,053
Percent change
from prior period (56.6)% (12.4)%
Cooling degree-days 667 495 965 756
Percent change
from prior period 34.7% 27.6%
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 number of market participants,
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.
41
Results of Operations for the Quarter and Nine Months Ended
September 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 59.
Overview
Net Income
Quarter Ended Nine Months Ended
September 30, September 30,
2002 2001 2002 2001
- --------------------------------------------------------------
(In millions)
Net Income (Loss) Before
Special Items Included
in Operations:
Merchant energy $145.6 $144.9 $239.1 $239.7
Regulated electric 36.9 27.3 88.1 73.0
Regulated gas (4.0) (2.3) 26.7 29.4
Other nonregulated (3.2) (6.8) (7.3) (20.5)
- ---------------------------------------------------------------
Net Income Before Special
Items Included in
Operations 175.3 163.1 346.6 321.6
Special Items Included in
Operations:
Gains on sale of
investments and
other assets -- 0.5 166.2 20.9
Workforce reduction
costs (7.5) -- (31.2) --
Impairment of
investments in
qualifying facilities (9.9) -- (9.9) --
Costs associated with
exit of BGE Home
merchandise stores (6.0) -- (6.0) --
Loss on sale of turbine -- -- (3.9) --
Impairment of real
estate and
international
investments (1.2) -- (1.2) --
- ---------------------------------------------------------------
Net Income Before
Cumulative Effect of
Change in Accounting
Principle 150.7 163.6 460.6 342.5
Cumulative Effect of
Change in Accounting
Principle -- -- -- 8.5
- ---------------------------------------------------------------
Net Income $150.7 $163.6 $460.6 $351.0
===============================================================
Quarter Ended September 30, 2002
Our total net income for the quarter ended September 30, 2002 decreased $12.9
million, or $.08 per share, compared to the same period of 2001 mostly because
we recorded the following special items:
o We recorded costs of $7.5 million after-tax, or $.04 per share, associated
with our corporate-wide workforce reduction program.
o Our merchant energy business recorded impairment losses of $9.9 million
after-tax, or $.06 per share, for the decline in value of certain
investments in partnerships that have investments in qualifying
facilities.
o Our other nonregulated businesses recorded costs of $6.0 million after-tax,
or $.04 per share, associated with the exit of the BGE Home retail
merchandise stores.
o Our other nonregulated businesses recorded impairment losses of $1.2 million
after-tax, or $.01 per share, on certain non-core real estate and
international investments.
We previously discussed these special items in the Events of 2002 section on
page 32.
These special items were partially offset by higher earnings before special
items in our regulated electric business primarily due to warmer weather in the
central Maryland region.
Our earnings before special items in our merchant energy business were
essentially the same compared to the same period of 2001, but were impacted by
the following:
o The addition of Nine Mile Point Nuclear Station (Nine Mile Point) to the
generation fleet increased net income.
o We benefited from the absence of Goldman Sachs' fees due to the
termination of the power business services agreement in October 2001.
o We had higher earnings from the addition of NewEnergy, which we acquired on
September 9, 2002.
These increases were offset by the following:
o We had lower mark-to-market results from our origination and risk management
operation.
o Our merchant energy business had lower earnings due to the impact of large
commercial and industrial customers leaving BGE's standard offer service
and electing other generation suppliers resulting in the sale of electricity
at lower prices.
o Our merchant energy business experienced higher purchased fuel costs.
42
Nine Months Ended September 30, 2002
Our total net income for the nine months ended September 30, 2002 increased
$109.6 million, or $.61 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 36.
o We had higher mark-to-market earnings from our origination and risk
management operation.
o The addition of Nine Mile Point Nuclear Station (Nine Mile Point) to the
generation fleet increased net income.
o We benefited from the absence of Goldman Sachs' fees due to the
termination of the power business services agreement in October 2001.
o We had higher earnings from our regulated electric business because of
warmer weather in the central Maryland region.
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 the addition of NewEnergy.
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 special items as previously
discussed in the Events of 2002 section on page 32 and the following:
o We had lower earnings due to the extended outage at Calvert Cliffs to
replace the steam generators at Unit 1.
o Our merchant energy business experienced higher purchased fuel costs and
lower energy prices in California.
o Our merchant energy business had lower earnings due to the impact of large
commercial and industrial customers leaving BGE's standard offer service
and electing other generation suppliers resulting in the sale of
electricity at lower prices.
In addition, our other nonregulated businesses recorded the following in the
first nine 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 $20.9 million after-tax, or $.13 per share.
Earnings per share contributions from all of our business segments for the
nine months ended September 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 38 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. As previously discussed in the Application of Critical Accounting
Policies section on page 28, during October 2002, the EITF reached a consensus
on Issue 02-3. When we apply that consensus, we will be required to record a
non-cash, cumulative effect of change in accounting principle that could have a
material one-time impact on our "Net income," "Mark-to-market energy assets and
liabilities," and "Common Shareholders' Equity." The consensus also will affect
our ongoing accounting for energy contracts. We describe this consensus on page
29.
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 certain load-serving activities, as discussed further in the
Physical Delivery Business section on page 51.
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.
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.
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 Mark-to-Market Origination and Risk Management
Revenues section on page 46. We discuss mark-to-market accounting and the
43
accounting policies for the merchant energy business further in the Application
of Critical Accounting Policies section on page 28 and in Note 1 of our 2001
Annual Report on Form 10-K.
As discussed in the Business Environment -- Electric Competition section on
page 38, 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.
Net Income
Quarter Ended Nine Months Ended
September 30, September 30,
2002 2001 2002 2001
- ---------------------------- ------- ------ --------- ---------
(In millions)
Revenues $832.0 $631.4 $1,880.1 $1,361.1
Fuel and purchased energy 314.2 176.3 647.0 391.5
Operations and maintenance 175.8 161.4 571.3 433.7
Workforce reduction costs 9.1 -- 19.4 --
Impairment losses 14.4 -- 20.4 --
Depreciation and
amortization 66.4 43.4 180.3 124.4
Taxes other than income
taxes 22.3 10.7 63.3 33.5
- ---------------------------- ------- ------ --------- ---------
Income from Operations $229.8 $239.6 $ 378.4 $ 378.0
============================ ======= ====== ========= =========
Net Income $130.3 $144.9 $ 213.7 $ 239.7
============================ ======= ====== ========= =========
Net Income Before Special
Items Included in
Operations $145.6 $144.9 $ 239.1 $ 239.7
Workforce reduction
costs (5.4) -- (11.6) --
Loss on sale of turbine -- -- (3.9) --
Impairment of
investments in
qualifying facilities (9.9) -- (9.9) --
- ---------------------------- ------- ------ --------- ---------
Net Income $130.3 $144.9 $ 213.7 $ 239.7
============================ ======= ====== ========= =========
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 16 provides a reconciliation
of operating results by segment to our Consolidated Financial Statements.
Revenues
Merchant energy revenues increased $200.6 million during the quarter ended
September 30, 2002 compared to the same period of 2001 mostly due to:
o recording revenues on a gross basis after the re-designation of our Texas
load-serving business to non-trading and the use of accrual accounting
for New England load-serving transactions entered into beginning in the
second quarter of 2002 as discussed in more detail on page 51,
o higher revenues from the sales of generation at Nine Mile Point, and
o revenues from NewEnergy, which we acquired in September 2002.
These increases were partially offset by a decrease in revenues related to
supplying BGE's standard offer service requirements and lower mark-to-market
origination and risk management revenues. Recording revenues on a gross versus
net basis does not affect the level of earnings, only the classification of the
components of gross margin between revenues and operating expenses.
Merchant energy revenues increased $519.0 million during the nine months
ended September 30, 2002 compared to the same period 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 and third
quarters of 2002, and Nine Mile Point,
o higher mark-to-market origination and risk management revenues,
o recording revenues on a gross basis after the re-designation of our Texas
load-serving business to non-trading and the use of accrual accounting
for New England load-serving transactions entered into beginning in the
second quarter of 2002, and
o revenues from NewEnergy.
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. Recording revenues on a
gross versus net basis does not affect the level of earnings, only the
classification of the components of gross margin between revenues and operating
expenses.
Our merchant energy business focuses on serving the full energy and capacity
requirements of various customers, such as utilities, municipalities,
cooperatives, retail aggregators, and certain commercial and industrial
customers. These load-serving activities occur in regional markets in which end
use customer electricity rates have been deregulated and thereby separated from
the cost of generation supply. Our generation operation (both owned assets and
ownership interests in domestic energy projects) and our
44
origination and risk management operation perform an integral role in executing
our nonregulated merchant energy business strategy.
We account for merchant energy revenues as follows:
o Load-serving and other physical delivery revenues include revenues we derive
from BGE standard offer service and other load-serving and physical
delivery activities and are generally subject to accrual accounting.
o Mark-to-market origination and risk management revenues include contracts
subject to mark-to-market accounting.
We discuss the changes in our merchant energy revenues in more detail below.
The consensus on EITF 02-3 could have a material impact on our revenues in the
future. We discuss the impact of this consensus in more detail in the EITF 02-3
section on page 29.
Load-Serving and Physical Delivery Revenues
Revenues from BGE Standard Offer Service
Revenues from BGE's Standard Offer Service requirements decreased by $49.4
million, including an increase in CTC revenues of $0.4 million during the
quarter ended September 30, 2002 compared to the same period of 2001.
The revenues from BGE's Standard Offer Service requirements decreased by
$71.7 million, including CTC revenues that decreased $6.4 million, during the
nine months ended September 30, 2002 compared to the same period of 2001.
These decreases were due to approximately 1,200 megawatts of large
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 is subject to future changes in wholesale
electricity prices.
The CTC revenues are impacted by the CTC rate our merchant energy business
receives from BGE customers as well as the volumes delivered to BGE customers.
The CTC rate declines over the transition period as previously discussed in the
Electric Competition - Maryland section on page 38. Accordingly, CTC revenues
may increase when we deliver more energy to BGE customers, but this increase
will be partially offset by a lower CTC rate.
Late in the second quarter of 2002, approximately one-third of the large
commercial and industrial customers that left BGE's standard offer service
elected BGE Home, a subsidiary of Constellation Energy, as their electric
generation supplier. Our merchant energy business continues to provide the
energy to BGE Home to meet the requirements of these customers under
market-based rates. Revenues from BGE Home were $22.4 million during the quarter
and $27.2 million during the nine months ended September 30, 2002.
Other Merchant Load-Serving and Physical Delivery Revenues
Other merchant load-serving and physical delivery revenues increased $287.3
million during the quarter and $528.1 million during the nine months ended
September 30, 2002 compared to the same periods of 2001. Our revenues by region
were as follows:
New York Region
Our merchant energy revenues in the New York region increased $175.3 million for
the quarter and $371.1 million for the nine months. This was due to revenues of
$156.0 million for the quarter and $351.8 million for the nine months from Nine
Mile Point, which was acquired in November 2001. We also recognized revenues of
$19.3 million for the quarter and nine months from NewEnergy, which we acquired
in September 2002.
Texas Region
Our merchant energy revenues in the Texas region increased $70.1 million for the
quarter and $172.5 million for the nine months mostly because of the following:
o revenues of $38.9 million for the quarter and $137.1 million for the nine
months related to the re-designation of the Texas load-serving business
to non-trading from mark-to-market energy revenues,
o revenues of $22.1 million for the quarter and $26.3 million for the nine
months from our Rio Nogales plant that commenced operations in the second
quarter of 2002, and
o revenues of $9.1 million for the quarter and nine months from NewEnergy.
The re-designation of existing contracts to non-trading did not have a material
impact on the Texas load-serving and physical delivery gross margin because the
increase in revenues was accompanied by a similar increase in fuel and purchased
energy expenses due to recording revenues and expenses on a gross basis under accrual
accounting.
Mid-Atlantic Region
Our merchant energy revenues in the Mid-Atlantic region were about the same
during the quarter and decreased by $42.1 million during the nine months mostly
because of the following:
o We had lower sales of power from our Baltimore plants in excess of that
required to serve BGE's standard offer service requirements compared to
same period 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.
45
o We recognized a $9.5 million gain on the sale of a project under development
in this region in 2001 that had a positive impact in that period.
New England Region
Our merchant energy revenues in the New England region increased $48.3 million
for the quarter and nine months due to $32.9 million for the New England
load-serving transactions entered into beginning in the second quarter of 2002
and revenues of $15.4 million from NewEnergy.
Mid-Continent Region
Our merchant energy revenues in the mid-continent region decreased $24.7 million
for the quarter and $18.0 million for the nine months mostly because we had
lower revenues from our gas-fired peaking facilities that commenced operations
in mid-summer of 2001 primarily due to lower demand for the output of these
facilities. These decreases were partially offset by revenues of $12.4 million
from NewEnergy.
Southeast Region
Our merchant energy revenues in the Southeast region increased $13.5 million for
the quarter and $16.4 million for the nine months mostly because of the new
generating facility that commenced operations beginning in the second quarter of
2002.
West Region
Our merchant energy revenues in the West region increased $6.0 million for the
quarter mostly because of revenues from NewEnergy. Our merchant energy revenues
in the West region decreased $2.0 million for the nine months mostly because of
lower revenues from our California projects partially offset by revenues from
NewEnergy. We discuss our California projects in more detail below.
California Power Purchase Agreements
- ------------------------------------
Our generation operation has $269.8 million invested in partnerships that own 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.
Revenues from these projects, net of credit reserves, were about the same
during the quarter and decreased $6.8 million for the nine months ended
September 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
September 30, 2002, we received $38.2 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.
Mark-to-Market 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 28 and in Note 1 in our 2001 Annual
Report on Form 10-K. We also discuss the EITF consensus on Issue 02-3 on page
29. This consensus could have a material impact on our revenues.
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.
46
Mark-to-market origination and risk management revenues were as follows:
Quarter Ended Nine Months Ended
September 30, September 30,
2002 2001 2002 2001
- ------------------------- -------- ------ ------- -------
(In millions)
Origination transactions $ 7.4 $25.7 $102.3 $129.2
Risk management activities
Realized 21.9 26.1 29.1 (21.1)
Unrealized (21.5) 15.7 30.5 18.4
- ------------------------- -------- ------ ------- -------
Total risk management
activities 0.4 41.8 59.6 (2.7)
- ------------------------- -------- ------ ------- -------
Total $ 7.8 $67.5 $161.9 $126.5
========================= ======== ====== ======= =======
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
mark-to-market origination and risk management revenues below. We show the
relationship between our revenues and the change in our net mark-to-market
energy asset on page 48.
Our mark-to-market origination and risk management revenues have been and
will continue to be affected by a decrease in the portion of our activities that
is subject to mark-to-market accounting. As discussed in the Physical Delivery
Business section on page 51, during 2002 we re-designated our Texas load-serving
business to accrual, and we began to account for new non-derivative origination
transactions on the accrual basis rather than under mark-to-market accounting.
Under the consensus on EITF 02-3, we will no longer record existing
non-derivative contracts at fair value beginning no later than January 1, 2003.
Further, effective July 1, 2002, to the extent that we are not able to observe
quoted market prices or other current market transactions for contract values
determined using models, we record a reserve to adjust such contracts to result
in zero gain or loss at inception. We remove the reserve and record such
contracts at fair value when we obtain current market information for contracts
with similar terms and counterparties.
We cannot predict the ongoing impact of applying EITF 02-3. However, we
expect that our reported earnings for contracts subject to the consensus will
generally match the cash flows from those contracts more closely and may be less
volatile under accrual accounting than under mark-to-market accounting, which
reflects changes in fair value of contracts when they occur rather than when
products are delivered and costs are incurred. Alternatively, other
comprehensive income may have greater fluctuations after we apply the consensus
because of a larger number of derivative contracts that we may designate for
hedge accounting under SFAS No. 133, but these fluctuations will not affect
earnings or cash flows. Additionally, because we will record revenues on a gross
basis under accrual accounting, our revenues could increase materially, but our
earnings will not be affected by this gross versus net reporting. We discuss the
consensus in detail on page 29.
Constellation Power Source's mark-to-market 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 mark-to-market
origination and risk management revenue in the table above reflects the nature
of the mark-to-market origination transactions that 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 49.
Mark-to-market origination and risk management revenues decreased $59.7
million during the quarter ended September 30, 2002 compared to the same period
of 2001 because of lower revenues from origination transactions and risk
management activities. The decrease in origination revenue reflects the use of
accrual accounting for new load-serving transactions originated beginning in the
second quarter of 2002, the impact of applying the EITF guidance on recording
gains at the time of contract origination as described on page 29, and fewer
transactions in 2002 as compared to the same period of 2001. The decrease in
revenues from risk management activities is primarily due to unfavorable changes
in regional power prices, price volatility, and other factors in the third
quarter of 2002 compared to the same period of 2001, partially offset by the
absence of mark-to-market losses recorded in 2001 on Texas trading activities
designated as non-trading in 2002.
Mark-to-market origination and risk management revenues increased $35.4
million during the nine months ended September 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 the absence of
mark-to-market losses recorded in 2001 on Texas trading activities designated as
non-trading in 2002, favorable changes in regional power prices, price
volatility, and other factors in 2002 compared to the same period of 2001. The
decrease in origination revenue reflects the use of accrual accounting for new
47
load-serving transactions originated beginning in the second quarter of 2002,
the impact of applying the EITF guidance on recording gains at the time of
contract origination as described on page 29, and 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. The non-derivative assets and liabilities primarily relate to
load-serving activities originated prior to the shift to accrual accounting
earlier this year. 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 50.
Mark-to-market energy assets and liabilities consisted of the following:
September 30, December 31,
2002 2001
- ------------------------------ -------------- ------------
(In millions)
Current assets $ 285.6 $ 398.4
Noncurrent assets 1,256.5 1,819.8
- ---------------------------------- ---------- -----------
Total assets 1,542.1 2,218.2
- ---------------------------------- ---------- -----------
Current liabilities 191.0 323.3
Noncurrent liabilities 855.6 1,476.5
- ---------------------------------- ---------- -----------
Total liabilities 1,046.6 1,799.8
- ---------------------------------- ---------- -----------
Net mark-to-market energy asset $ 495.5 $ 418.4
================================== ========== ===========
The primary components of our net mark-to-market energy asset are the
following as of September 30, 2002:
(In millions)
New England load-serving $303.7
PJM generation hedge 111.0
Other positions 80.8
- ------------------------------- ---------------
Total $495.5
=============================== ===============
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. Under the consensus on EITF 02-3, we will cease
to account for a portion of these contracts at fair value beginning no later
than January 1, 2003. We discuss the impact of the consensus on EITF 02-3 in
more detail on page 29.
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 $80.8 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 the quarter and the nine months ended
September 30, 2002:
Change in Net Mark-to-Market Energy Asset
Quarter Ended Nine Months Ended
September 30, September
2002 30, 2002
- -------------------------------- ---------------- --------------
(In millions)
Fair value beginning of period $509.0 $418.4
Changes in fair value recorded as
revenues
Origination transactions $ 7.4 $102.3
------ ------
Unrealized risk management
revenues:
Reclassification of settled
contracts to realized (21.9) (29.1)
Changes in valuation
techniques 6.5 10.8
Unrealized changes in fair
value (6.1) 48.8
------ ------
Total unrealized risk
management revenues $(21.5) $ 30.5
------ ------
Total changes in fair value
recorded as revenues (14.1) 132.8
Changes in fair value recorded as
operating expenses 2.6 5.6
Changes in value of
exchange-listed futures and
options 20.1 21.1
Net change in premiums on options (28.2) (38.8)
Texas contracts re-designated
as non-trading -- (63.3)
Other changes in fair value 6.1 19.7
- ----------------------------------- ------ ------- ------ ------
Fair value at September 30, 2002 $495.5 $495.5
=================================== ====== ======= ====== ======
Origination transactions represent the initial unrealized fair value at the
time these contracts are executed. Reclassification of settled contracts to
realized represents the portion of previously unrealized amounts settled during
the period and recorded as realized transactions. 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 revenues. Changes in value of exchange-listed futures and
options represent unrealized revenue from exchange-traded contracts
48
included in risk management revenues. The fair value of these contracts is recorded
in "Accounts receivable" rather than mark-to-market energy assets in our Consolidated
Balance Sheets because these amounts are settled through our margin account with a
third-party broker.
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.
We discuss our re-designation of the Texas load-serving activities as
non-trading in more detail on page 51.
The settlement term of the net mark-to-market energy asset and sources of
fair value as of September 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 $17.5 $73.4 $(26.8) $(70.2) $ 2.5 $ (0.7) $ (1.6) $4.7 $ (1.2)
Prices based on
models (3.4) (4.0) 109.7 101.1 71.8 64.9 159.9 (3.3) 496.7
- --------------------- ---------- --------- --------- --------- ---------- ---------- ---------- ----------- ----------
Total net
mark-to-market
energy asset $14.1 $69.4 $ 82.9 $ 30.9 $74.3 $ 64.2 $158.3 $1.4 $495.5
===================== ========== ========= ========= ========= ========== ========== ========== =========== ==========
The implementation of the consensus on EITF 02-3 for existing non-derivative
contracts in our mark-to-market portfolio will impact the amount and composition
of the net mark-to-market energy asset. We discuss this consensus in more detail
on page 29.
The portion of the net mark-to-market energy asset as of September 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 51, 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 52.
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 $35.9 $65.5 $17.6 $(38.2) $ 2.3 $(2.5) $(5.1) $ -- $ 75.5
Prices based on
models -- 2.5 (7.9) 22.9 34.2 23.7 28.5 12.4 116.3
- --------------------- ---------- --------- --------- --------- -------- ---------- ---------- ----------- ----------
Total $35.9 $68.0 $ 9.7 $(15.3) $36.5 $21.2 $23.4 $12.4 $191.8
===================== ========== ========= ========= ========= ======== ========== ========== =========== ==========
49
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
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 2008, depending upon the region,
o forward purchases and sales of electricity during off-peak hours for
delivery terms through 2008, 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,
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
that 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, the
o 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 contracts, 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 can be readily
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
50
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 September 30, 2002.
These amounts do not represent the contractual maturities 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
Our merchant energy business focuses on serving the full energy and capacity
requirements of various customers, such as utilities, municipalities,
cooperatives, retail aggregators, and large commercial and industrial customers.
These load-serving activities occur in regional markets in which end use
customer electricity rates have been deregulated and thereby separated from the
cost of generation supply. Our merchant energy business manages these activities
as a physical delivery business rather than a trading 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. We
describe our accounting for these activities below, including the use of
mark-to-market accounting for certain portions of our load-serving activities.
Under accrual accounting 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.
On October 25, 2002, the EITF reached a consensus on Issue 02-3, that will
affect how we apply the mark-to-market method of accounting and, among other
things, requires us to begin using the accrual method of accounting for certain
existing load-serving contracts for which we previously were required to apply
mark-to-market accounting. We discuss the impact of the consensus on EITF 02-3
in more detail on page 29.
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. The consensus on EITF 02-3 requires us to remove
the unamortized balance of these assets and liabilities, excluding the costs of
any acquired contracts, from our Consolidated Balance Sheets no later than
January 1, 2003.
51
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 $38.9 million for the quarter ended
September 30, 2002 and $137.1 million for the period February 15, 2002 through
September 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." Mark-to-market 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 loss of $28.0 million for the third quarter
of 2001 and a net loss of $36.2 million for the nine months ended September 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 retail customers and 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. Therefore, we use accrual accounting for New England load-serving
transactions and associated power purchase agreements entered into since the
second quarter of 2002.
Because EITF 98-10 significantly limited the circumstances under which
contracts previously designated as a trading activity could be re-designated as
non-trading, prior to the consensus on EITF 02-3, we were required to continue
to include contracts entered into before the second quarter of 2002 in our
mark-to-market accounting portfolio under EITF 98-10. However, the consensus on
EITF 02-3 will affect the accounting for these contracts no later than January
1, 2003 when we will be required to remove these contracts from our
"Mark-to-market energy assets and liabilities" and begin to account for these
contracts under the accrual method of accounting.
Operating Expenses
Fuel and Purchased Energy
Merchant energy fuel and purchased energy expenses increased $137.9 million
during the quarter ended September 30, 2002 compared to the same period of 2001
mostly because of the following:
o We had higher fuel and purchased energy of $75.2 million related to
recording fuel and purchased energy costs gross after the re-designation
of our Texas load-serving business to non-trading and the use of accrual
accounting for New England transactions entered into beginning in the
second quarter of 2002 as previously discussed on page 51. Recording
purchased fuel and energy costs on a gross versus net basis does not
affect the level of earnings, only the classification of the components
of gross margin between revenues and operating expenses.
o We had higher purchased energy of $54.2 million for NewEnergy to meet their
load requirements.
o We had higher fuel and purchased energy of $35.9 million from the operations
of the new generating facilities and Nine Mile Point.
o We had higher purchased energy to supply BGE standard offer service due to
the warmer weather and higher coal prices. These were partially offset by
lower generation at our coal plants. We expect to incur higher coal
prices through the remainder of 2002.
These increases were offset by lower fuel and purchased energy of $46.5
million at our mid-continent gas-fired peaking facilities primarily due to lower
demand for the output of these facilities.
Merchant energy fuel and purchased energy expenses increased $255.5 million
for the nine months ended September 30, 2002 compared to the same period of 2001
mostly because of the following:
o We had higher fuel and purchased energy of $177.7 million related to
recording fuel and purchased energy costs after the re-designation of our
Texas load-serving business to non-trading and the use of accrual
accounting for New England load-serving transactions entered into
beginning in the second quarter of 2002 as discussed above. Recording
purchased fuel and energy costs on a gross versus net basis does not
affect the level of earnings, only the classification of the components
of gross margin between revenues and operating expenses.
o We had higher fuel and purchased energy of $57.4 million from the operations
of the new generating facilities and Nine Mile Point.
o We had higher purchased energy of $54.2 million for NewEnergy.
o We had higher purchased energy to supply BGE standard offer service due to
the warmer weather, the extended outage at Calvert Cliffs, and higher
coal prices. These were partially offset by lower generation at our coal
plants.
52
These increases were offset by lower fuel and purchased energy of $39.1
million at our mid-continent gas-fired peaking facilities.
The consensus on EITF 02-3 could have a material impact on our fuel and
purchased energy costs in the future because we will begin to account for
certain non-derivative contracts on a gross basis under the accrual method of
accounting, rather than on a net basis under the mark-to-market method of
accounting. We discuss this consensus in more detail on page 29.
Operations and Maintenance Expenses
Merchant operations and maintenance expenses increased $14.4 million during the
quarter and $137.6 million for the nine months ended September 30, 2002 compared
to the same periods of 2001 mostly because of the following:
o We had operations and maintenance expenses of $48.1 million for the quarter
and $156.0 million for the nine months ended at the new generating
facilities and Nine Mile Point, and $2.4 million at NewEnergy.
o Origination and risk management operating expenses were about the same for
the quarter and $19.7 million higher for the nine months as a result of
the growth of this operation.
These increased costs were partially offset by the following:
o Our origination and risk management operation benefited from the absence
of Goldman Sachs' fees due to the termination of the power business
services agreement in October 2001. The Goldman Sachs fees were $17.4
million in the third quarter of 2001 and $29.0 million for the nine
months of 2001.
o We had cost reductions due to productivity initiatives associated with our
corporate-wide workforce reduction.
o Our origination and risk management operation had lower direct expenses of
$14.4 million for the quarter related to fewer origination transactions
compared to the same period of 2001. These direct expenses were about the
same for the nine months ended compared to the same period 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 which
was completed 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 this extended outage. Calvert Cliffs will replace the steam generators for
Unit 2 during the 2003 refueling outage. Based on our current outage schedule,
we expect the 2003 extended outage to be shorter than the 2002 extended outage.
However, the extended outage will be significantly longer than a normal
refueling outage. As a result of the extended outages, we expect lower annual
revenues and higher annual operating costs from Calvert Cliffs compared to 2001.
Workforce Reduction Costs
Our merchant energy business recognized expenses of $9.1 million pre-tax, or
$5.4 million after-tax, during the quarter and $19.4 million pre-tax, or $11.6
million after-tax, for the nine months associated with our workforce reduction
efforts as previously discussed in the Events of 2002 section on page 33.
Once our workforce reduction efforts to date have been fully implemented,
our merchant energy business expects ongoing, full year labor cost savings of
approximately $32 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.
Impairment Losses
As discussed in the Events of 2002 section on page 32, our merchant energy
business recognized impairment losses of $14.4 million pre-tax, or $9.9 million
after-tax, for the decline in value of certain investments in partnerships that
have investments in qualifying facilities. In addition, our merchant energy
business 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 $23.0 million
during the quarter and $55.9 million for the nine months ended September 30,
2002 compared to the same periods of 2001 mostly because of the depreciation and
amortization associated with Nine Mile Point and the new generating facilities.
Taxes Other than Income Taxes
Merchant energy taxes other than income taxes increased $11.6 million during the
quarter and $29.8 million for the nine months ended September 30, 2002 compared
to the same periods of 2001 mostly because of taxes other than income taxes
associated with Nine Mile Point and the new generating facilities.
53
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 38.
Net Income
Quarter Ended Nine Months Ended
September 30, September 30,
2002 2001 2002 2001
- ---------------------------- ------- ------ -------- ----------
(In millions)
Revenues $596.3 $634.6 $1,537.1 $1,624.4
Electric fuel and
purchased energy 358.6 418.0 872.9 977.7
Operations and maintenance 67.8 60.2 188.1 184.9
Workforce reduction costs 3.1 -- 31.9 --
Depreciation and
amortization 43.6 43.7 131.4 130.5
Taxes other than income
taxes 35.5 36.0 104.4 107.0
- ---------------------------- ------- ------ -------- ----------
Income from Operations $ 87.7 $ 76.7 $ 208.4 $ 224.3
============================ ======= ====== ======== ==========
Net Income $ 35.0 $ 27.3 $ 68.8 $ 73.0
============================ ======= ====== ======== ==========
Net Income Before Special
Items Included in
Operations $ 36.9 $ 27.3 $ 88.1 $ 73.0
Workforce reduction
costs (1.9) -- (19.3) --
- ---------------------------- ------- ------ -------- ----------
Net Income $ 35.0 $ 27.3 $ 68.8 $ 73.0
============================ ======= ====== ======== ==========
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 16 provides a reconciliation
of operating results by segment to our Consolidated Financial Statements.
Net income from the regulated electric business increased during the quarter
ended September 30, 2002 compared to the same period of 2001 mostly because of
increased distribution sales volumes due to warmer weather. Net income from the
regulated electric business decreased during the nine months ended September 30,
2002 compared to the same period of 2001 primarily because we recorded costs of
$19.3 million after-tax associated with our workforce reduction initiatives,
partially offset by increased distribution sales volumes due to warmer weather
and an increased number of customers.
Electric Revenues
The changes in electric revenues in 2002 compared to 2001 were caused by:
Quarter Ended Nine Months Ended
September 30, September 30,
2002 vs. 2001 2002 vs. 2001
- -----------------------------------------------------------
(In millions)
Distribution sales
volumes $ 16.8 $ 15.0
Standard Offer Service (43.9) (61.1)
Fuel rate surcharge (15.4) (42.7)
- -----------------------------------------------------------
Total change in electric
revenues from electric
system sales (42.5) (88.8)
Other 4.2 1.5
- -----------------------------------------------------------
Total change in
electric revenues $(38.3) $(87.3)
===========================================================
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 Nine Months Ended
September 30, September 30,
2002 vs. 2001 2002 vs. 2001
- -------------------------------------------------------
Residential 14.2% 4.4%
Commercial 6.1 1.8
Industrial 4.6 0.9
During the quarter ended September 30, 2002, we distributed more electricity
to all customers compared to the same period of 2001 due to warmer weather.
During the nine months ended September 30, 2002, we distributed more electricity
to residential customers compared to the same period of 2001 due to warmer
weather and an increased number of customers. We distributed more electricity to
commercial customers compared to the same period of 2001 due to higher usage per
customer and an increased number of customers. We distributed about the same
amount of electricity to industrial customers.
54
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 and nine months
ended September 30, 2002 compared to the same periods 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 increased sales to residential customers due
to warmer summer weather and 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 Nine Months Ended
September 30, September 30,
2002 2001 2002 2001
- --------------------------------------------------------
(In millions)
Actual costs $358.6 $402.9 $872.9 $935.8
Net recovery of
costs under
electric fuel
rate clause -- 15.1 -- 41.9
- --------------------------------------------------------
Total electric
fuel and
purchased
energy expenses $358.6 $418.0 $872.9 $977.7
========================================================
Actual Costs
As discussed in the Business Environment--Electric Competition section on page
38, 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 nine
months ended September 30, 2002 were lower compared to the same periods of 2001
mostly because BGE purchased less energy due to large 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 electric operations and maintenance expenses increased $7.6 million
for the quarter and $3.2 million for the nine months ended September 30, 2002
compared to the same periods of 2001 mostly because of increased spending to
improve the reliability of our electric distribution system. These higher costs
were partially offset by cost reductions due to productivity initiatives
associated with our corporate-wide workforce reduction and other productivity
initiative programs during the nine months ended compared to the same period of
2001.
Workforce Reduction Costs
BGE's electric business recognized expenses of $3.1 million pre-tax, or $1.9
million after-tax, during the quarter and $31.9 million pre-tax, or $19.3
million after-tax, for the nine months associated with our workforce reduction
efforts as previously discussed in the Events of 2002 section on page 33.
Once our workforce reduction efforts to date have been fully implemented,
BGE's electric business expects ongoing, full year labor 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 nine months ended September 30, 2002 compared to the same periods of 2001.
55
Regulated Gas Business
Net Income
Quarter Ended Nine Months Ended
September 30, September 30,
2002 2001 2002 2001
- --------------------------------------------------------------
(In millions)
Gas revenues $72.2 $66.8 $388.1 $534.1
Gas purchased for resale 28.3 22.9 191.3 328.0
Operations and maintenance 25.1 23.2 71.0 72.4
Workforce reduction costs 0.2 -- 0.2 --
Depreciation and
amortization 11.5 9.8 36.0 36.3
Taxes other than income
taxes 7.5 7.2 24.7 25.6
- ---------------------------------------------------------------
(Loss) Income from
operations $(0.4) $ 3.7 $ 64.9 $ 71.8
===============================================================
Net (Loss) Income $(4.1) $(2.3) $ 26.6 $ 29.4
===============================================================
Net (Loss) Income Before
Special Items Included
in Operations $(4.0) $(2.3) $ 26.7 $ 29.4
Workforce reduction
costs (0.1) -- (0.1) --
- ---------------------------------------------------------------
Net (Loss) Income $(4.1) $(2.3) $ 26.6 $ 29.4
===============================================================
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 16 provides a reconciliation
of operating results by segment to our Consolidated Financial Statements.
Net loss from the regulated gas business was about the same during the quarter
ended September 30, 2002 compared to the same period of 2001. Net income from
the regulated gas business decreased during the nine months ended September 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 Nine Months Ended
September 30, September 30,
2002 vs. 2001 2002 vs. 2001
- -------------------------------------------------------------
(In millions)
Distribution volumes $(1.5) $ (14.5)
Base rates -- (2.3)
Weather normalization 2.3 12.2
Gas cost adjustments 1.4 (99.7)
- -------------------------------------------------------------
Total change in gas revenues
from gas system sales 2.2 (104.3)
Off-system sales 3.6 (38.9)
Other (0.4) (2.8)
- --------------------------------------------------------------
Total change in gas revenues $ 5.4 $(146.0)
=============================================================
Distribution Volumes
The percentage changes in our gas distribution volumes, by type of customer, in
2002 compared to 2001 were:
Quarter Ended Nine Months Ended
September 30, September 30,
2002 vs. 2001 2002 vs. 2001
- --------------------------------------------------------
Residential (6.4)% (11.2)%
Commercial (11.6) (2.1)
Industrial (4.4) (5.1)
During the quarter ended September 30, 2002, we distributed less gas to
residential and commercial customers compared to the same period of 2001 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 nine months ended September 30, 2002, we distributed less gas to
residential and commercial 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 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 were about the same for the quarter ended September 30, 2002
compared to the same period of 2001. Base rate revenues decreased for the nine
months ended September 30, 2002 compared to the same period of 2001 mostly
because of a decrease in the rate approved by the Maryland PSC associated with
the energy conservation surcharge program.
56
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 $2.4 million during the nine
months ended September 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 ended September 30, 2002, gas cost adjustment revenues
were about the same compared to the same period of 2001.
During the nine months ended September 30, 2002, gas cost adjustment
revenues decreased compared to the same period 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.
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 September 30, 2002, revenues from off-system gas
sales increased mostly because we sold more gas as compared to the same period
of 2001. During the nine months ended September 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 compared to the same period of 2001.
Gas Purchased For Resale Expenses
Gas purchased for resale expenses include the cost of gas purchased for resale
to our customers and for off-system sales. These costs do not include the cost
of gas purchased by delivery service customers.
During the quarter ended September 30, 2002, gas costs increased compared to
the same period of 2001 because we purchased more gas at a higher price.
During the nine months ended September 30, 2002, gas costs decreased compared
to the same period of 2001 because we purchased less gas at a lower price.
Gas Operations and Maintenance Expenses
Regulated gas operations and maintenance expenses were about the same for the
quarter and nine months ended September 30, 2002 compared to the same periods of
2001.
Workforce Reduction Costs
BGE's gas business recognized expenses associated with our workforce reduction
efforts as previously discussed in the Events of 2002 section on page 33.
Once our workforce reduction efforts to date have been fully implemented,
BGE's gas business expects ongoing, full year labor 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.
Other Gas Operating Expenses
Regulated other gas operating expenses were about the same for the quarter and
nine months ended September 30, 2002 compared to the same periods of 2001.
57
Other Nonregulated Businesses
Net Income
Quarter Ended Nine Months Ended
September 30, September 30,
2002 2001 2002 2001
- --------------------------------------------------------------
(In millions)
Revenues $133.5 $112.4 $385.6 $422.2
Operating expenses 126.8 108.3 360.0 387.0
Workforce reduction costs 0.1 -- 0.2 --
Impairment losses and other
costs 10.2 -- 10.2 --
Depreciation and
amortization 4.3 6.0 12.4 17.3
Taxes other than income
taxes 1.2 1.3 3.3 3.5
Gains on sale of
investments and other
assets -- 0.7 260.3 34.4
- -------------------------------------------------------------
(Loss) Income from
Operations $ (9.1) $ (2.5) $259.8 $ 48.8
==============================================================
Net Income Before
Cumulative Effect of
Change in Accounting
Principle $(10.5) $ (6.3) $151.5 $ 0.4
Cumulative Effect of Change
in Accounting Principle -- -- -- 8.5
- --------------------------------------------------------------
Net (Loss) Income $(10.5) $ (6.3) $151.5 $ 8.9
==============================================================
Net (Loss) Income Before
Special Items Included
in Operations $ (3.2) $ (6.8) $ (7.3) $(20.5)
Gains on sale of
investments and
other assets -- 0.5 166.2 20.9
Workforce reduction
costs (0.1) -- (0.2) --
Impairment of real
estate and
international
investments (1.2) -- (1.2) --
Costs associated with
exit of BGE Home
merchandise stores (6.0) -- (6.0) --
- --------------------------------------------------------------
Net (Loss) Income Before
Cumulative Effect of
Change in Accounting
Principle $(10.5) $ (6.3) $151.5 $ 0.4
Cumulative Effect of Change
in Accounting Principle -- -- -- 8.5
- --------------------------------------------------------------
Net (Loss) Income $(10.5) $ (6.3) $151.5 $ 8.9
==============================================================
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 16 provides a reconciliation
of operating results by segment to our Consolidated Financial Statements.
During the quarter ended September 30, 2002, the loss from operations at our
other nonregulated businesses increased compared to the same period of 2001
mostly because of impairment losses and other costs of $10.2 million, as
previously discussed in the Events of 2002 section on page 33, partially offset
by better performance by our international business in the third quarter of
2002.
During the nine months ended September 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 36 and higher earnings from the growth of our energy services business
and improved results from our international business. This gain was partially
offset by $10.2 million of impairment losses and other costs recorded in 2002
and gains on the sale of securities in 2001 that had a positive impact in that
period, including the $14.8 million pre-tax gain on the sale of one million
shares of our Orion investment, 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 included 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, which we sold in October 2002, 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 September
30, 2002, we liquidated approximately 55% of our investment portfolio since the
beginning of the year.
58
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 and nine months ended September 30, 2002, total fixed charges
increased compared to the same periods of 2001 mostly because of a higher level
of debt outstanding at higher interest rates.
During the quarter and nine months ended September 30, 2002, total fixed
charges at BGE decreased compared to the same periods of 2001 mostly because of
a lower level of debt outstanding and lower interest rates.
Income Taxes
During the quarter and nine months ended September 30, 2002, our total income
taxes increased compared to the same periods of 2001 mostly because of higher
taxable income.
Financial Condition
Cash Flows
Cash provided by operations was $655.7 million for the nine months ended
September 30, 2002 compared to $643.3 million in 2001.
For the nine months ended September 30, 2002, cash used in investing
activities was $116.2 million compared to $908.2 million in 2001. The decrease
in cash used in investing activities 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.
This was partially offset by the acquisition of NewEnergy (net of cash acquired)
for $207.8 million in September 2002.
Cash used in financing activities for the nine months ended September 30,
2002 was $153.6 million compared to cash provided of $146.2 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. This was partially offset by higher
issuance of debt during 2002.
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-
59
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 $2.3 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 $2.3 billion of debt issued in 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 of $640 million and a $640 million three-year revolving credit
facility. These two new facilities allow our issuance 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 September 30, 2002,
Constellation Energy had $296.1 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 $200 million in annual committed credit facilities, expiring May
through November of 2003, in order to allow commercial paper to be issued. As of
September 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.
On August 28, 2002, BGE called $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 were redeemed 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.
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.
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 on the next page.
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 on the next
page because of a number of factors including:
o completion of our 2003 annual capital budgeting process,
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 67.
60
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 34.
Capital Requirements
Merchant Energy Business
Our merchant energy business will require additional funding for the following:
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 18.
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. 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 September 30, 2002, the outstanding lease balance plus other
committed expenses was $570.2 million.
Our wholly owned subsidiary, High Desert Power Project LLC, is supervising
the construction of, and leasing, the High Desert project from High Desert Power
Trust, an independent special purpose entity created to own and lease the
project to our subsidiary. Neither Constellation Energy nor any affiliate owns
any equity or other interest in High Desert Power Trust, which is owned by a
consortium of banks and other financial institutions. We provide a guaranty of
High Desert Power Project LLC's obligations to the Trust.
Current accounting rules require that an SPE lessor must have sufficient
independent equity at risk in order for us not to consolidate it. High Desert
Power Trust maintains such a level of equity at risk, since the owners of the
Trust maintain a minimum of 3% real equity at risk. It should be noted that the
FASB is currently considering amending the accounting rules governing SPE's. If
the FASB does issue new guidance, we will need to re-evaluate the requirement to
consolidate the Trust under any new guidance.
The lease with the Trust contains several events of default that are
commonly found in financings of this type, including failure to make all
payments when due, failure to comply with all covenants, violation of material
representations and warranties and change of control. In addition, several
events of default are applicable to us as guarantor, including defaults in other
material financing agreements and failure to own 100% of BGE's common stock.
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.
61
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.
The projects that our merchant energy business develop typically require
substantial capital investment. Most of the projects recently constructed were
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. In the second quarter of 2002,
Constellation Energy made a $200 million capital contribution to BGE. BGE also
participates in a cash pool with Constellation Energy as discussed in the Notes
to Consolidated Financial Statements section on page 22.
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.
Our ability to sell or liquidate securities and non-core assets will depend
on market conditions, and we cannot give assurances that these sales or
liquidations could be made. We discuss our remaining non-core assets and market
conditions in the Other Nonregulated Businesses section on page 58.
Committed Amounts
Our total contractual and contingent obligations as of September 30, 2002,
including obligations with contract durations less than one year, are shown in
the following table:
Payments/Expiration
- -----------------------------------------------------------------
2003- 2005- There-
2002 2004 2006 after Total
- -----------------------------------------------------------------
(In millions)
Contractual Obligations
- -----------------------------------------------------------------
Short-term $18.6 $ -- $ -- $ -- $18.6
borrowings
Nonregulated
long-term debt1 0.3 49.2 301.4 2,611.3 2,962.2
BGE long-term
debt1 173.0 435.7 506.9 957.4 2,073.0
BGE preference
stock -- -- -- 190.0 190.0
Fuel and
transportation 97.2 505.6 85.4 12.8 701.0
Purchased
capacity and
energy2 194.9 522.2 94.0 93.4 904.5
Operating leases 5.1 83.4 72.1 175.4 336.0
Capital and loan
commitments3 24.3 28.7 -- -- 53.0
- -----------------------------------------------------------------
Total contractual
obligations 513.4 1,624.8 1,059.8 4,040.3 7,238.3
- -----------------------------------------------------------------
Contingent Obligations
Letters of
credit 162.7 133.4 -- -- 296.1
Guarantees -
origination
and risk
management
operation4 1,060.8 305.1 86.0 182.6 1,634.5
Other guarantees,
net5 294.1 132.1 603.0 142.8 1,172.0
- -----------------------------------------------------------------
Total contingent
obligations 1,517.6 570.6 689.0 325.4 3,102.6
- -----------------------------------------------------------------
Total obligations $2,031.0 $2,195.4 $1,748.8 $4,365.7 $10,340.9
=================================================================
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.
2 Our contractual obligations for purchased capacity and energy are shown on a
gross basis for certain transactions, including contracts in Texas that were
re-designated and NewEnergy.
3 Amounts related to capital expenditures are included for applicable periods in
our capital requirements table on page 61.
4 Our calculation of the fair value of obligations under these guarantees was
$403 million at September 30, 2002.
5 Other guarantees in the above table are shown net of liabilities recorded at
September 30, 2002 in our Consolidated Balance Sheets.
62
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 contracts. We discuss the expected settlement
terms of these contracts on page 49.
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 $ 35 $ 35
BBB-/Baa3 2 95 130
Below investment
grade 3 370 500
At September 30, 2002, we had approximately $1.2 billion of unused credit
facilities and $458.3 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 that 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 long-term debt indentures of Constellation Energy and BGE do
not contain material adverse change clauses or financial covenants.
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. Failure by Constellation Energy to comply with these covenants
could result in the maturity of the debt outstanding under these facilities
being accelerated. At September 30, 2002, Constellation Energy is in compliance
with these covenants.
The credit facilities of Constellation Energy contain usual and customary
cross-default provisions that apply to defaults on debt by Constellation Energy
and certain subsidiaries over a specified threshold. BGE's credit facility also
contains usual and customary cross-default provisions that apply to defaults on
debt by BGE over a specified threshold. The indentures pursuant to which BGE has
issued and outstanding mortgage bonds and subordinated debentures provide that a
default under any debt instrument issued under the relevant indenture may cause
a default of all debt outstanding under such indenture.
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.
63
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 17 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 24.
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 17,
o activities of our origination and risk management operation in the Merchant
Energy Business section of Management's Discussion and Analysis beginning
on page 43, and
o changes to our business environment in the Business Environment section of
Management's Discussion and Analysis beginning on page 38.
Item 4. Controls and Procedures
The principal executive officers and principal financial officer of both
Constellation Energy and BGE have evaluated the effectiveness of the disclosure
controls and procedures (as such term is defined in Rules 13a-14(c) and
15d-14(c) under the Securities Exchange Act of 1934, as amended (the "Exchange
Act")) as of a date within 90 days prior to the filing date of this quarterly
report (the "Evaluation Date"). Based on such evaluation, such officers have
concluded that, as of the Evaluation Date, Constellation Energy and BGE's
disclosure controls and procedures are effective in alerting them on a timely
basis to material information relating to Constellation Energy and BGE required
to be included in Constellation Energy and BGE's periodic filings under the
Exchange Act.
Since the Evaluation Date, there have been no significant changes in either
Constellation Energy's or BGE's internal controls or in other factors that could
significantly affect such controls.
64
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. After several postponements, a
hearing is now scheduled for January 6, 2003 on that order.
NewEnergy
Constellation NewEnergy, Inc. v. PowerWeb Technology, Inc. -- Prior to our
acquisition, NewEnergy filed a complaint on May 9, 2002 in the U.S. District
Court of Eastern Pennsylvania seeking approximately $100,000 in damages relating
to a contract previously entered into with PowerWeb. PowerWeb Technology has
counter-claimed seeking $100 million in damages against NewEnergy. To date, no
discovery has occurred. We cannot predict the timing, or outcome, of the action
or its possible effect on our financial results. However, based on the
information available to Constellation Energy at this time, we believe NewEnergy
has meritorious defenses to the PowerWeb Technology counterclaim.
Mercury Poisoning
Beginning in September 2002, BGE, Constellation Energy, and several other
defendants have been involved in several actions alleging mercury poisoning from
several sources, including coal plants formerly owned by BGE. The plants are now
owned by a subsidiary of Constellation Energy. In addition to BGE and
Constellation Energy, approximately 11 other defendants, consisting of
pharmaceutical companies, manufacturers of vaccines and manufacturers of
Thimerosal have been sued. Approximately 48 cases have been filed to date, with
each case seeking $90 million in damages from the group of defendants. The
claims were originally filed in the Circuit Court for Baltimore City, Maryland
beginning in September 2002, but have been removed to Federal district court for
the District of Maryland. The plaintiffs have filed motions to remand the cases
back to the Baltimore City Circuit Court. At this time no discovery has
occurred. We cannot predict the timing, or outcome, of these cases, or their
possible effect on our, or BGE's, financial results.
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 do not believe class certification is appropriate and we further
believe that BGE has meritorious defenses to the underlying claims and intends
to defend the action vigorously. However, we cannot predict the timing, or
outcome, of the action or its possible effect on our, or BGE's, financial
results.
65
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
575 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, 50 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.
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, we are
unable to estimate what our, or BGE's, liability, 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 effect on our, or
BGE's, financial results 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 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. BGE
believes it has meritorious defenses and intends to defend the action
vigorously. However, we cannot predict the timing, or outcome, of the action or
its possible effect on our, or BGE's, financial results.
66
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 and performance 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 September 30, 2002:
Date Items Reported
August 14, 2002 Item 9. Regulation FD Disclosure
August 23, 2002 Item 5. Other Events
Item 7. Financial Statements and Exhibits
67
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, each
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
CONSTELLATION ENERGY GROUP, INC.
--------------------------------------------
(Registrant)
BALTIMORE GAS AND ELECTRIC COMPANY
--------------------------------------------
(Registrant)
Date: November 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
68
CONSTELLATION ENERGY GROUP, INC. CERTIFICATIONS
I, Mayo A. Shattuck, III, certify that:
1. I have reviewed this quarterly report on Form 10-Q of Constellation
Energy Group, Inc.;
2. Based on my knowledge, this quarterly report does not contain any
untrue statement of a material fact or omit to state a material
fact necessary to make the statements made, in light of the
circumstances under which such statements were made, not
misleading with respect to the period covered by this quarterly
report;
3. Based on my knowledge, the financial statements, and other
financial information included in this quarterly report, fairly
present in all material respects the financial condition, results
of operations and cash flows of the registrant as of, and for, the
periods presented in this quarterly report;
4. The registrant's other certifying officers and I are responsible
for establishing and maintaining disclosure controls and
procedures (as defined in Exchange Act Rules 13a-14 and 15d-14)
for the registrant and we have:
a) designed such disclosure controls and procedures to ensure
that material information relating to the registrant,
including its consolidated subsidiaries, is made known to us
by others within those entities, particularly during the
period in which this quarterly report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to
the filing date of this quarterly report (the "Evaluation
Date"); and
c) presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures based
on our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed,
based on our most recent evaluation, to the registrant's auditors
and the audit committee of registrant's board of directors (or
persons performing the equivalent function):
a) All significant deficiencies in the design or operation of
internal controls which could adversely affect the
registrant's ability to record, process, summarize and report
financial data and have identified for the registrant's
auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management
or other employees who have a significant role in the
registrant's internal controls; and
6. The registrant's other certifying officers and I have indicated in
this quarterly report whether or not there were significant
changes in internal controls or in other factors that could
significantly affect internal controls subsequent to the date of
our most recent evaluation, including any corrective actions with
regard to significant deficiencies and material weaknesses.
November 14, 2002
/s/ Mayo A. Shattuck, III
--------------------------------
Chairman of the Board, Chief Executive Officer and President
69
CONSTELLATION ENERGY GROUP, INC. CERTIFICATIONS
I, E. Follin Smith, certify that:
1. I have reviewed this quarterly report on Form 10-Q of Constellation
Energy Group, Inc.;
2. Based on my knowledge, this quarterly report does not contain any
untrue statement of a material fact or omit to state a material
fact necessary to make the statements made, in light of the
circumstances under which such statements were made, not
misleading with respect to the period covered by this quarterly
report;
3. Based on my knowledge, the financial statements, and other
financial information included in this quarterly report, fairly
present in all material respects the financial condition, results
of operations and cash flows of the registrant as of, and for, the
periods presented in this quarterly report;
4. The registrant's other certifying officers and I are responsible
for establishing and maintaining disclosure controls and
procedures (as defined in Exchange Act Rules 13a-14 and 15d-14)
for the registrant and we have:
a) designed such disclosure controls and procedures to ensure
that material information relating to the registrant,
including its consolidated subsidiaries, is made known to us
by others within those entities, particularly during the
period in which this quarterly report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to
the filing date of this quarterly report (the "Evaluation
Date"); and
c) presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures based
on our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed,
based on our most recent evaluation, to the registrant's auditors
and the audit committee of registrant's board of directors (or
persons performing the equivalent function):
a) All significant deficiencies in the design or operation of
internal controls which could adversely affect the
registrant's ability to record, process, summarize and report
financial data and have identified for the registrant's
auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management
or other employees who have a significant role in the
registrant's internal controls; and
6. The registrant's other certifying officers and I have indicated in
this quarterly report whether or not there were significant
changes in internal controls or in other factors that could
significantly affect internal controls subsequent to the date of
our most recent evaluation, including any corrective actions with
regard to significant deficiencies and material weaknesses.
November 14, 2002
/s/ E. Follin Smith
-------------------------
Senior Vice President and Chief Financial Officer
70
BALTIMORE GAS AND ELECTRIC COMPANY CERTIFICATIONS
I, Frank O. Heintz, certify that:
1. I have reviewed this quarterly report on Form 10-Q of Baltimore Gas
and Electric Company;
2. Based on my knowledge, this quarterly report does not contain any
untrue statement of a material fact or omit to state a material
fact necessary to make the statements made, in light of the
circumstances under which such statements were made, not
misleading with respect to the period covered by this quarterly
report;
3. Based on my knowledge, the financial statements, and other
financial information included in this quarterly report, fairly
present in all material respects the financial condition, results
of operations and cash flows of the registrant as of, and for, the
periods presented in this quarterly report;
4. The registrant's other certifying officers and I are responsible
for establishing and maintaining disclosure controls and
procedures (as defined in Exchange Act Rules 13a-14 and 15d-14)
for the registrant and we have:
a) designed such disclosure controls and procedures to ensure
that material information relating to the registrant,
including its consolidated subsidiaries, is made known to us
by others within those entities, particularly during the
period in which this quarterly report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to
the filing date of this quarterly report (the "Evaluation
Date"); and
c) presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures based
on our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed,
based on our most recent evaluation, to the registrant's auditors
and the audit committee of registrant's board of directors (or
persons performing the equivalent function):
a) All significant deficiencies in the design or operation of
internal controls which could adversely affect the
registrant's ability to record, process, summarize and report
financial data and have identified for the registrant's
auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management
or other employees who have a significant role in the
registrant's internal controls; and
6. The registrant's other certifying officers and I have indicated in
this quarterly report whether or not there were significant
changes in internal controls or in other factors that could
significantly affect internal controls subsequent to the date of
our most recent evaluation, including any corrective actions with
regard to significant deficiencies and material weaknesses.
November 14, 2002
/s/ Frank O. Heintz
--------------------------------
President and Chief Executive Officer
71
BALTIMORE GAS AND ELECTRIC COMPANY CERTIFICATIONS
I, E. Follin Smith, certify that:
1. I have reviewed this quarterly report on Form 10-Q of Baltimore Gas
and Electric Company;
2. Based on my knowledge, this quarterly report does not contain any
untrue statement of a material fact or omit to state a material
fact necessary to make the statements made, in light of the
circumstances under which such statements were made, not
misleading with respect to the period covered by this quarterly
report;
3. Based on my knowledge, the financial statements, and other
financial information included in this quarterly report, fairly
present in all material respects the financial condition, results
of operations and cash flows of the registrant as of, and for, the
periods presented in this quarterly report;
4. The registrant's other certifying officers and I are responsible
for establishing and maintaining disclosure controls and
procedures (as defined in Exchange Act Rules 13a-14 and 15d-14)
for the registrant and we have:
a) designed such disclosure controls and procedures to ensure
that material information relating to the registrant,
including its consolidated subsidiaries, is made known to us
by others within those entities, particularly during the
period in which this quarterly report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to
the filing date of this quarterly report (the "Evaluation
Date"); and
c) presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures based
on our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed,
based on our most recent evaluation, to the registrant's auditors
and the audit committee of registrant's board of directors (or
persons performing the equivalent function):
a) All significant deficiencies in the design or operation of
internal controls which could adversely affect the
registrant's ability to record, process, summarize and report
financial data and have identified for the registrant's
auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management
or other employees who have a significant role in the
registrant's internal controls; and
6. The registrant's other certifying officers and I have indicated in
this quarterly report whether or not there were significant
changes in internal controls or in other factors that could
significantly affect internal controls subsequent to the date of
our most recent evaluation, including any corrective actions with
regard to significant deficiencies and material weaknesses.
November 14, 2002
/s/ E. Follin Smith
--------------------------------
Senior Vice President and Chief Financial Officer
72
Baltimore Gas & Electric
Filed: 14 Nov 02, 12:00am