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, 2000
Commission Exact name of registrant IRS Employer
File Number as specified in its charter Identification No.
- ----------- --------------------------- -----------------
1-12869 CONSTELLATION ENERGY GROUP, INC. 52-1964611
1-1910 BALTIMORE GAS AND ELECTRIC COMPANY 52-0280210
MARYLAND
-----------------------------------
(State of Incorporation)
250 W. PRATT STREET, BALTIMORE, MARYLAND 21201
--------------------- --------------------- -------
(Address of principal executive offices) (Zip Code)
410-234-5000
------------
(Registrants' telephone number, including area code)
NOT APPLICABLE
------------------------------
(Former name, former address
and former fiscal year, if changed since last report)
Indicate by check mark whether the registrants (1) have filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months, and (2) have been subject to such filing
requirements for the past 90 days.
Yes X No
----
Common Stock, without par value 150,531,716 shares outstanding of Constellation
Energy Group, Inc. on October 31, 2000.
TABLE OF CONTENTS
Page
Part I -- Financial Information
Item 1 -- Financial Statements
Constellation Energy Group, Inc. and Subsidiaries
Consolidated Statements of Income...................................................... 3
Consolidated Statements of Comprehensive Income........................................ 3
Consolidated Balance Sheets............................................................ 4
Consolidated Statements of Cash Flows.................................................. 6
Baltimore Gas and Electric Company and Subsidiaries
Consolidated Statements of Income...................................................... 7
Consolidated Statements of Comprehensive Income........................................ 7
Consolidated Balance Sheets............................................................ 8
Consolidated Statements of Cash Flows.................................................. 10
Notes to Consolidated Financial Statements............................................. 11
Item 2 -- Management's Discussion and Analysis of Financial Condition and Results of Operations
Introduction........................................................................... 18
Strategy............................................................................... 19
Current Issues......................................................................... 20
Results of Operations.................................................................. 24
Financial Condition.................................................................... 32
Capital Resources...................................................................... 33
Other Matters.......................................................................... 35
Item 3 -- Quantitative and Qualitative Disclosures About Market Risk............................. 35
Part II -- Other Information
Item 1 -- Legal Proceedings...................................................................... 36
Item 5 -- Other Information...................................................................... 37
Item 6 -- Exhibits and Reports on Form 8-K....................................................... 38
Signature........................................................................................ 39
2
CONSTELLATION ENERGY GROUP, INC. AND SUBSIDIARIES
PART I - FINANCIAL INFORMATION
Item 1 - Financial Statements
Consolidated Statements of Income (Unaudited)
Three Months Ended Nine Months Ended
September 30, September 30,
2000 1999 2000 1999
-------- -------- -------- --------
(In Millions, Except Per-Share Amounts)
Revenues
Nonregulated revenues $ 296.7 $ 258.9 $ 781.4 $ 782.2
Regulated electric revenues 598.2 691.2 1,688.0 1,737.2
Regulated gas revenues 86.7 60.1 372.8 332.7
-------- -------- -------- --------
Total revenues 981.6 1,010.2 2,842.2 2,852.1
Expenses
Operating expenses 512.2 574.5 1,680.8 1,761.3
Depreciation and amortization 107.6 92.9 370.7 274.0
Taxes other than income taxes 46.4 65.1 158.8 177.2
-------- -------- -------- --------
Total expenses 666.2 732.5 2,210.3 2,212.5
-------- -------- -------- --------
Income From Operations 315.4 277.7 631.9 639.6
Other Income 0.9 1.2 7.0 5.7
-------- -------- -------- --------
Income Before Fixed Charges and Income Taxes 316.3 278.9 638.9 645.3
Fixed Charges
Interest expense (net) 66.6 61.7 192.0 181.1
BGE preference stock dividends 3.3 3.4 9.9 10.2
-------- -------- -------- --------
Total fixed charges 69.9 65.1 201.9 191.3
-------- -------- -------- --------
Income Before Income Taxes 246.4 213.8 437.0 454.0
Income Taxes
Current 108.3 76.7 215.1 152.6
Deferred (7.3) 3.2 (31.0) 20.9
Investment tax credit adjustments (2.1) (2.2) (6.3) (6.4)
-------- -------- -------- --------
Total income taxes 98.9 77.7 177.8 167.1
-------- -------- -------- --------
Net Income $ 147.5 $ 136.1 $ 259.2 $ 286.9
======== ======== ======== ========
Earnings Applicable to Common Stock $ 147.5 $ 136.1 $ 259.2 $ 286.9
======== ======== ======== ========
Average Shares of Common Stock Outstanding 150.1 149.6 149.8 149.6
Earnings per Common Share and Earnings
Per Common Share Assuming Dilution $0.98 $0.91 $1.73 $1.92
Dividends Declared Per Common Share $0.42 $0.42 $1.26 $1.26
Consolidated Statements of Comprehensive Income (Unaudited)
Three Months Ended Nine Months Ended
September 30, September 30,
2000 1999 2000 1999
-------- -------- -------- --------
(In Millions)
Net Income $ 147.5 $ 136.1 $ 259.2 $ 286.9
Other comprehensive income (loss), net of taxes 17.7 5.0 41.8 (6.5)
-------- -------- -------- --------
Comprehensive Income $ 165.2 $ 141.1 $ 301.0 $ 280.4
======== ======== ======== ========
See Notes to Consolidated Financial Statements.
Certain prior period amounts have been reclassified to conform with the current
period's presentation.
3
CONSTELLATION ENERGY GROUP, INC. AND SUBSIDIARIES
PART I - FINANCIAL INFORMATION (CONTINUED)
Item 1 - Financial Statements
Consolidated Balance Sheets
September 30, December 31,
2000* 1999
------------- -------------
(In Millions)
Assets
Current Assets
Cash and cash equivalents $ 50.4 $ 92.7
Accounts receivable (net of allowance for uncollectibles
of $25.5 and $36.6 respectively) 842.1 578.5
Trading securities 180.2 136.5
Assets from energy trading activities 1,573.7 312.1
Fuel stocks 101.9 94.9
Materials and supplies 155.6 149.1
Prepaid taxes other than income taxes 140.2 72.4
Other 36.4 54.0
------------- -------------
Total current assets 3,080.5 1,490.2
Investments and Other Assets
Real estate projects and investments 296.4 310.1
Investments in power projects 538.8 547.3
Financial investments 192.2 145.4
Nuclear decommissioning trust fund 235.0 217.9
Net pension asset 97.2 99.5
Investment in Orion Power Holdings, Inc. 232.1 105.7
Other 120.4 154.3
------------- -------------
Total investments and other assets 1,712.1 1,580.2
Property, Plant and Equipment
Regulated property, plant and equipment:
Plant in service 4,746.0 8,620.1
Construction work in progress 68.8 222.3
Plant held for future use 9.7 13.0
------------- -------------
Total regulated property, plant and equipment 4,824.5 8,855.4
Nonregulated generation property, plant and equipment 4,906.5 341.3
Other nonregulated property, plant and equipment 165.1 152.7
Nuclear fuel (net of amortization) 137.4 133.8
Accumulated depreciation (3,745.6) (3,559.1)
------------- -------------
Net property, plant and equipment 6,287.9 5,924.1
Deferred Charges
Regulatory assets (net) 514.2 637.4
Other 61.3 51.9
------------- -------------
Total deferred charges 575.5 689.3
------------- -------------
Total Assets $ 11,656.0 $ 9,683.8
============= =============
* Unaudited
See Notes to Consolidated Financial Statements.
Certain prior period amounts have been reclassified to conform with the current
period's presentation.
4
CONSTELLATION ENERGY GROUP, INC. AND SUBSIDIARIES
PART I - FINANCIAL INFORMATION (CONTINUED)
Item 1 - Financial Statements
Consolidated Balance Sheets
September 30, December 31,
2000* 1999
------------- -------------
(In Millions)
Liabilities and Capitalization
Current Liabilities
Short-term borrowings $ 505.0 $ 371.5
Current portion of long-term debt 660.9 808.3
Accounts payable 693.7 365.1
Liabilities from energy trading activities 1,260.6 163.8
Dividends declared 66.2 66.1
Accrued taxes 90.8 19.2
Other 206.8 209.4
------------- -------------
Total current liabilities 3,484.0 2,003.4
Deferred Credits and Other Liabilities
Deferred income taxes 1,273.9 1,288.8
Postretirement and postemployment benefits 261.7 269.8
Deferred investment tax credits 103.4 109.6
Other 355.7 253.8
------------- -------------
Total deferred credits and other liabilities 1,994.7 1,922.0
Long-term Debt
First refunding mortgage bonds of BGE 1,174.7 1,321.7
Other long-term debt of BGE 603.6 1,135.8
Company obligated mandatorily redeemable trust preferred
securities of subsidiary trust holding solely 7.16% debentures
of BGE due June 30, 2038 250.0 250.0
Long-term debt of nonregulated businesses 1,477.2 686.8
Unamortized discount and premium (9.3) (10.6)
Current portion of long-term debt (660.9) (808.3)
------------- -------------
Total long-term debt 2,835.3 2,575.4
BGE Preference Stock Not Subject to Mandatory Redemption 190.0 190.0
Common Shareholders' Equity
Common stock 1,540.9 1,494.0
Retained earnings 1,569.4 1,499.1
Accumulated other comprehensive income (loss) 41.7 (0.1)
------------- -------------
Total common shareholders' equity 3,152.0 2,993.0
------------- -------------
Total capitalization 6,177.3 5,758.4
------------- -------------
Total Liabilities and Capitalization $ 11,656.0 $ 9,683.8
============= =============
* Unaudited
See Notes to Consolidated Financial Statements.
Certain prior period amounts have been reclassified to conform with the current
period's presentation.
5
CONSTELLATION ENERGY GROUP, INC. AND SUBSIDIARIES
PART I - FINANCIAL INFORMATION (CONTINUED)
Item 1 - Financial Statements
Consolidated Statements of Cash Flows (Unaudited)
Nine Months Ended
September 30,
2000 1999
----------- -----------
(In Millions)
Cash Flows From Operating Activities
Net income $ 259.2 $ 286.9
Adjustments to reconcile to net cash provided by operating activities
Depreciation and amortization 411.1 316.2
Deferred income taxes (31.0) 20.9
Investment tax credit adjustments (6.3) (6.4)
Deferred fuel costs 11.0 (51.2)
Accrued pension and postemployment benefits 18.1 35.5
Gain on sale of subsidiaries (13.3) -
Write-down of real estate investment - 5.2
Write-down of financial investment - 33.8
Write-off of power project - 10.2
Equity in earnings of affiliates and joint ventures (net) (6.3) 22.4
Changes in assets from energy trading activities (1,261.6) (74.1)
Changes in liabilities from energy trading activities 1,096.8 (12.3)
Changes in other current assets (243.3) (355.5)
Changes in other current liabilities 270.1 234.8
Other 84.3 17.1
----------- -----------
Net cash provided by operating activities 588.8 483.5
----------- -----------
Cash Flows From Investing Activities
Purchases of property, plant and equipment and
other capital expenditures (626.9) (351.9)
Contributions to nuclear decommissioning trust fund (13.5) (13.2)
Purchases of marketable equity securities (36.3) (17.2)
Sales of marketable equity securities 39.6 12.5
Other financial investments 10.4 15.1
Real estate projects and investments 9.3 46.2
Power projects investments (14.9) (11.0)
Investment in Orion Power Holdings, Inc. (101.5) (97.7)
Other 5.4 (24.6)
----------- -----------
Net cash used in investing activities (728.4) (441.8)
----------- -----------
Cash Flows From Financing Activities
Proceeds from issuance of
Short-term borrowings 7,883.8 2,412.2
Long-term debt 803.0 289.7
Common stock 35.9 9.5
Repayments of short-term borrowings (7,750.3) (2,269.1)
Reacquisitions of long-term debt (691.8) (399.6)
Redemption of preference stock - (7.0)
Common stock dividends paid (188.5) (188.3)
Other 5.2 (6.4)
----------- -----------
Net cash provided by (used in) financing activities 97.3 (159.0)
----------- -----------
Net Decrease in Cash and Cash Equivalents (42.3) (117.3)
Cash and Cash Equivalents at Beginning of Period 92.7 173.7
----------- -----------
Cash and Cash Equivalents at End of Period $ 50.4 $ 56.4
=========== ===========
Other Cash Flow Information:
Interest paid (net of amounts capitalized) $ 205.0 $ 174.9
Income taxes paid $ 136.1 $ 102.2
See Notes to Consolidated Financial Statements.
Certain prior period amounts have been reclassified to conform with the current
period's presentation.
6
BALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARIES
PART I - FINANCIAL INFORMATION
Item 1 - Financial Statements
Consolidated Statements of Income (Unaudited)
Three Months Ended Nine Months Ended
September 30, September 30,
2000 1999 2000 1999
--------- ---------- ---------- ----------
(In Millions)
Revenues
Electric Revenues $ 598.4 $ 691.4 $ 1,688.4 $ 1,737.5
Gas Revenues 90.1 62.9 377.8 337.3
Nonregulated Revenues 1.5 1.7 3.9 346.7
--------- ---------- ---------- ----------
Total revenues 690.0 756.0 2,070.1 2,421.5
Operating Expenses
Electric fuel and purchased energy 388.3 130.0 632.4 375.3
Gas purchased for resale 48.2 21.3 192.0 156.4
Operations and maintenance 88.0 167.1 457.5 539.2
Nonregulated - selling, general, and administrative 1.0 1.1 2.8 285.3
Depreciation and amortization 63.8 89.0 313.6 267.5
Taxes other than income taxes 35.7 64.2 146.2 175.6
--------- ---------- ---------- ----------
Total operating expenses 625.0 472.7 1,744.5 1,799.3
--------- ---------- ---------- ----------
Income From Operations 65.0 283.3 325.6 622.2
Other Income
Allowance for equity funds used during construction 0.6 1.5 2.1 5.2
Equity in earnings of Safe Harbor Water Power Corporation - 1.2 2.4 3.8
Net other income (expense) 3.7 (0.5) 5.4 (3.6)
--------- ---------- ---------- ----------
Total other income 4.3 2.2 9.9 5.4
--------- ---------- ---------- ----------
Income Before Fixed Charges and Income Taxes 69.3 285.5 335.5 627.6
Fixed Charges
Interest expense (net) 45.3 48.1 142.2 162.3
Capitalized interest - - - (0.4)
Allowance for borrowed funds used during construction (0.3) (0.8) (2.9) (2.8)
--------- ---------- ---------- ----------
Total fixed charges 45.0 47.3 139.3 159.1
--------- ---------- ---------- ----------
Income Before Income Taxes 24.3 238.2 196.2 468.5
Income Taxes
Current 17.9 80.5 119.8 169.1
Deferred (6.3) 4.9 (38.8) 3.5
Investment tax credit adjustments (0.6) (2.1) (4.7) (6.4)
--------- ---------- ---------- ----------
Total income taxes 11.0 83.3 76.3 166.2
--------- ---------- ---------- ----------
Net Income 13.3 154.9 119.9 302.3
Preference Stock Dividends 3.3 3.4 9.9 10.2
--------- ---------- ---------- ----------
Earnings Applicable to Common Stock $ 10.0 $ 151.5 $ 110.0 $ 292.1
========= ========== ========== ==========
Consolidated Statements of Comprehensive Income (Unaudited)
Three Months Ended Nine Months Ended
September 30, September 30,
2000 1999 2000 1999
--------- ---------- ---------- ----------
(In Millions)
Net Income $ 13.3 $ 154.9 $ 119.9 $ 302.3
Other comprehensive loss, net of taxes - - - (3.4)
--------- ---------- ---------- ----------
Comprehensive Income $ 13.3 $ 154.9 $ 119.9 $ 298.9
========= ========== ========== ==========
See Notes to Consolidated Financial Statements.
Certain prior period amounts have been reclassified to conform with the current
period's presentation.
7
BALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARIES
PART I - FINANCIAL INFORMATION (CONTINUED)
Item 1 - Financial Statements
Consolidated Balance Sheets
September 30, December 31,
2000* 1999
-------------- ---------------
(In Millions)
Assets
Current Assets
Cash and cash equivalents $ 16.9 $ 23.5
Accounts receivable (net of allowance for uncollectibles
of $13.9 and $13.0 respectively) 389.2 316.1
Notes receivable, affilated company 87.0 -
Fuel stocks 56.9 94.9
Materials and supplies 38.8 139.1
Prepaid taxes other than income taxes 108.5 72.4
Other 8.0 9.0
-------------- ---------------
Total current assets 705.3 655.0
Investments and Other Assets
Nuclear decommissioning trust fund - 217.9
Net pension asset 103.8 99.8
Safe Harbor Water Power Corporation - 34.5
Other 63.0 61.6
-------------- ---------------
Total investments and other assets 166.8 413.8
Utility Plant
Plant in service
Electric 3,234.3 7,088.6
Gas 983.1 962.0
Common 528.6 569.5
-------------- ---------------
Total plant in service 4,746.0 8,620.1
Accumulated depreciation (1,674.9) (3,466.1)
-------------- ---------------
Net plant in service 3,071.1 5,154.0
Construction work in progress 68.8 222.3
Nuclear fuel (net of amortization) - 133.8
Plant held for future use 9.7 13.0
-------------- ---------------
Net utility plant 3,149.6 5,523.1
Deferred Charges
Regulatory assets (net) 514.2 637.4
Other 39.1 43.3
-------------- ---------------
Total deferred charges 553.3 680.7
-------------- ---------------
Total Assets $ 4,575.0 $ 7,272.6
============== ===============
* Unaudited
See Notes to Consolidated Financial Statements.
8
BALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARIES
PART I - FINANCIAL INFORMATION (CONTINUED)
Item 1 - Financial Statements
Consolidated Balance Sheets
September 30, December 31,
2000* 1999
-------------- ---------------
(In Millions)
Liabilities and Capitalization
Current Liabilities
Short-term borrowings $ 258.0 $ 129.0
Current portion of long-term debt 309.7 523.9
Accounts payable 336.7 222.8
Customer deposits 43.7 40.6
Dividends declared 3.3 3.3
Accrued taxes 11.4 9.2
Accrued interest 36.4 48.2
Accrued vacation costs 22.7 35.7
Other 20.1 65.8
-------------- ---------------
Total current liabilities 1,042.0 1,078.5
Deferred Credits and Other Liabilities
Deferred income taxes 507.0 1,032.0
Postretirement and postemployment benefits 250.6 231.0
Deferred investment tax credits 25.6 109.6
Decommissioning of federal uranium enrichment facilities 27.2 27.2
Other 24.7 42.9
-------------- ---------------
Total deferred credits and other liabilities 835.1 1,442.7
Long-term Debt
First refunding mortgage bonds of BGE 1,174.7 1,321.7
Other long-term debt of BGE 603.6 1,135.8
Company obligated mandatorily redeemable trust preferred
securities of subsidiary trust holding solely 7.16% debentures
of BGE due June 30, 2038 250.0 250.0
Long-term debt of nonregulated businesses 33.0 33.0
Unamortized discount and premium (7.1) (10.6)
Current portion of long-term debt (309.7) (523.9)
-------------- ---------------
Total long-term debt 1,744.5 2,206.0
Preference Stock Not Subject to Mandatory Redemption 190.0 190.0
Common Shareholder's Equity
Common stock 454.2 1,494.0
Retained earnings 309.2 861.4
-------------- ---------------
Total common shareholder's equity 763.4 2,355.4
-------------- ---------------
Total capitalization 2,697.9 4,751.4
-------------- ---------------
Total Liabilities and Capitalization $ 4,575.0 $ 7,272.6
============== ===============
* Unaudited
See Notes to Consolidated Financial Statements.
9
BALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARIES
PART I - FINANCIAL INFORMATION (CONTINUED)
Item 1 - Financial Statements
Consolidated Statements of Cash Flows (Unaudited)
Nine Months Ended
September 30,
2000 1999
------------ -----------
(In Millions)
Cash Flows From Operating Activities
Net income $ 119.9 $ 302.3
Adjustments to reconcile to net cash provided by operating activities
Depreciation and amortization 338.2 307.6
Deferred income taxes (38.8) 3.6
Investment tax credit adjustments (4.7) (6.4)
Deferred fuel costs 11.0 (51.2)
Accrued pension and postemployment benefits 14.9 35.0
Allowance for equity funds used during construction (2.1) (5.2)
Equity in earnings of affiliates and joint ventures (net) 1.2 29.0
Changes in assets from energy trading activities - (120.1)
Changes in liabilities from energy trading activities - 76.3
Changes in other current assets (127.0) (73.2)
Changes in other current liabilities 158.1 41.9
Other 5.2 32.5
------------ -----------
Net cash provided by operating activities 475.9 572.1
------------ -----------
Cash Flows From Investing Activities
Utility construction expenditures (including AFC) (241.0) (246.1)
Allowance for equity funds used during construction 2.1 5.2
Nuclear fuel expenditures (39.5) (45.0)
Deferred energy conservation expenditures (0.5) (0.9)
Contributions to nuclear decommissioning trust fund (8.8) (13.2)
Purchases of marketable equity securities - (9.2)
Sales of marketable equity securities - 6.0
Other financial investments - 6.7
Real estate projects and investments - 22.0
Power projects investments - (17.9)
Other (5.5) (16.7)
------------ -----------
Net cash used in investing activities (293.2) (309.1)
------------ -----------
Cash Flows From Financing Activities
Proceeds from issuance of
Short-term borrowings 3,655.0 1,608.3
Long-term debt - 257.2
Common stock - 9.5
Repayments of short-term borrowings (3,526.0) (1,585.8)
Reacquisition of long-term debt (121.7) (375.3)
Redemption of preference stock - (7.0)
Preference stock dividends paid (9.9) (10.3)
Distributions to Constellation Energy (188.5) (316.5)
Other 1.8 (1.3)
------------ -----------
Net cash used in financing activities (189.3) (421.2)
------------ -----------
Net Decrease in Cash and Cash Equivalents (6.6) (158.2)
Cash and Cash Equivalents at Beginning of Period 23.5 173.7
------------ -----------
Cash and Cash Equivalents at End of Period $ 16.9 $ 15.5
============ ===========
Other Cash Flow Information:
Interest paid (net of amounts capitalized) $ 147.0 $ 155.0
Income taxes paid $ 111.5 $ 99.4
Non-Cash Transactions
- ---------------------
On July 1, 2000, BGE transferred $1,578.4 million of generation assets net of
associated liabilities to affiliates of Constellation Energy pursuant to the
Maryland PSC's Restructuring Order.
See Notes to Consolidated Financial Statements.
10
Notes to Consolidated Financial Statements
- ------------------------------------------
Weather conditions can have a great impact on our results for interim periods.
This means that results for interim periods do not necessarily represent results
to be expected for the year.
Our interim financial statements on the previous pages reflect all adjustments
that Management believes are necessary for the fair presentation of the
financial position and results of operations for the interim periods presented.
These adjustments are of a normal recurring nature.
Holding Company Formation
- -------------------------
On April 30, 1999, Constellation Energy(R) Group, Inc. (Constellation Energy)
became the holding company for Baltimore Gas and Electric Company (BGE(R)) and
Constellation(R) Enterprises, Inc. Constellation Enterprises was previously
owned by BGE. BGE's outstanding common stock automatically became shares of
common stock of Constellation Energy. BGE's debt securities, obligated
mandatorily redeemable trust preferred securities, and preference stock remain
securities of BGE.
Basis of Presentation
- ---------------------
This Quarterly Report on Form 10-Q is a combined report of Constellation Energy
and BGE. The consolidated financial statements of Constellation Energy include
the accounts of Constellation Energy, BGE and its subsidiaries, Constellation
Enterprises, Inc. and its subsidiaries, and Constellation Nuclear, LLC and its
subsidiaries. The consolidated financial statements of BGE include the accounts
of BGE, District Chilled Water General Partnership (ComfortLink), and BGE
Capital Trust I. As Constellation Enterprises and its subsidiaries were
subsidiaries of BGE prior to April 30, 1999, they are included in the
consolidated financial statements of BGE through that date.
References in this report to "we" and "our" are to Constellation Energy and its
subsidiaries, collectively. Reference in this report to the "utility business"
is to BGE.
Deregulation of Electric Generation
- -----------------------------------
On April 8, 1999, Maryland enacted legislation authorizing customer choice and
competition among electric suppliers. In addition, on November 10, 1999, the
Maryland Public Service Commission (Maryland PSC) issued a Restructuring Order
that resolved the major issues surrounding electric restructuring. Effective
July 1, 2000, the state of Maryland implemented customer choice for electric
suppliers. We discuss the implications of customer choice and the Restructuring
Order further in Management's Discussion and Analysis beginning on page 18.
Please also refer to the Legal Proceedings section on page 36 for a discussion
regarding appeals of the Restructuring Order.
Subsequent Event
- ----------------
On October 23, 2000, we announced three initiatives to advance our growth
strategies. The first initiative is that we entered into an agreement (the
"Agreement") with an affiliate of The Goldman Sachs Group, Inc. ("Goldman
Sachs"). Under the terms of the Agreement, Goldman Sachs will acquire up to a
17.5% equity interest in our domestic merchant energy business, which will be
consolidated under a single holding company ("Holdco"). Goldman Sachs will also
acquire a ten-year warrant for up to 13% of Holdco's common stock (subject to
certain adjustments). The warrant is exercisable six months after Holdco's
common stock becomes publicly available. The amount of common stock which
Goldman Sachs may receive upon exercise will be equal to the excess of the
market price of Holdco's common stock at the time of exercise over the exercise
price of $60 per share for all the stock subject to the warrant, divided by the
market price. Holdco may at its option pay Goldman Sachs such excess in cash.
Goldman Sachs is acquiring its interest and the warrant in exchange for $250
million in cash (subject to adjustment in certain instances) and certain assets
related to our power marketing business. At closing, Goldman Sachs' existing
services agreement with our power marketing business will terminate.
The second initiative is a plan to separate our domestic merchant energy
business from our retail services business. The separation will create two
stand-alone, publicly traded energy companies. One will be a merchant energy
business engaged in wholesale power marketing and generation under the name
"Constellation Energy Group" after the separation. The other will be a regional
retail energy and energy services company, BGE Corp., that will include BGE and
other subsidiaries.
The third initiative is a change in our common stock dividend policy effective
April 2001. We will maintain our current common stock dividend through January
2001. In a move closely aligned with our separation plan, effective April 2001,
our annual dividend is expected to be set at $.48 per share. After the business
separation, BGE Corp. expects to pay initial annual dividends of $.48 per share.
Constellation Energy Group, as a growing merchant energy company, expects to
initially reinvest its earnings and not pay a dividend in order to fund its
aggressive growth plans.
11
The closing of the transaction with Goldman Sachs and the separation are subject
to customary closing conditions, including regulatory approvals and the receipt
of a Private Letter Ruling from the Internal Revenue Service regarding certain
tax matters. Both are expected to be completed by mid to late 2001.
We discuss these strategic initiatives further in our Report on Form 8-K and
exhibits filed October 23, 2000.
Information by Operating Segment
- --------------------------------
In 1999, we reported three operating business segments -- Electric, Gas, and
Energy Services. In response to the deregulation of electric generation, we
realigned our organization and combined our wholesale power marketing business
with our domestic plant development and operations to form a domestic merchant
energy business.
In the first quarter of 2000, we revised our operating segments to reflect the
realignments of our organization. Our new reportable operating segments are --
Domestic Merchant Energy, Regulated Electric, and Regulated Gas:
o Our nonregulated domestic merchant energy business:
- provides power marketing and risk management services,
- develops, owns, and operates domestic power projects, and
- provides nuclear consulting services.
o Our regulated electric business purchases and distributes electricity, and
o Our regulated gas business purchases, transports, and sells natural gas.
We have restated certain prior period information for comparative purposes based
on our new reportable operating segments.
Effective July 1, 2000, the financial results of the electric generation portion
of our business are included in the domestic merchant energy business segment.
Prior to that date, the financial results of electric generation are included in
our regulated electric business.
Our remaining nonregulated businesses:
o develop, own, and operate international power projects in Latin America,
o provide energy products and services,
o sell and service electric and gas appliances, and heating and air
conditioning systems, engage in home improvements, and sell electricity and
natural gas through mass marketing efforts,
o provide cooling services,
o engage in financial investments, and
o develop, own and manage real estate and senior-living facilities.
Domestic 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)
2000
- ----
Unaffiliated revenues $ 127.9 $ 598.2 $ 86.7 $ 168.8 $ - $ 981.6
Intersegment revenues 367.7 0.1 3.4 19.0 (390.2) -
------------ ---------------- --------------- ------------- ------------ --------------
Total revenues 495.6 598.3 90.1 187.8 (390.2) 981.6
Net income (loss) 130.9 15.4 (4.6) 5.8 - 147.5
1999
- ----
Unaffiliated revenues $ 66.3 $ 691.2 $ 60.1 $ 192.6 $ - $ 1,010.2
Intersegment revenues - 0.2 2.8 14.5 (17.5) -
------------- ---------------- --------------- ------------- ------------- ------------
Total revenues 66.3 691.4 62.9 207.1 (17.5) 1,010.2
Net income (loss) (a) 12.2 152.3 (0.7) (27.7) - 136.1
12
Domestic Unallocated
Merchant Regulated Regulated Other Corporate
Energy Electric Gas Nonregulated Items and
Business Business Business Businesses Eliminations Consolidated
-------------- ------------ ---------------- ------------- --------------- ------------
For the nine months ended September 30, (in millions)
2000
- ----
Unaffiliated revenues $ 261.3 $1,688.0 $ 372.8 $ 520.1 $ - $ 2,842.2
Intersegment revenues 367.6 0.4 5.0 37.3 (410.3) -
------------ -------------- ---------------- ------------- ------------- ------------
Total revenues 628.9 1,688.4 377.8 557.4 (410.3) 2,842.2
Net income (loss) (b) 150.2 93.2 18.1 (2.3) - 259.2
1999
- ----
Unaffiliated revenues $ 173.3 $ 1,737.2 $ 332.7 $ 608.9 $ - $ 2,852.1
Intersegment revenues 0.4 0.7 7.4 26.2 (34.7) -
------------ -------------- ------------ ------------ ------------- --------------
Total revenues 173.7 1,737.9 340.1 635.1 (34.7) 2,852.1
Net income (loss) (a) 43.6 253.4 21.5 (31.6) - 286.9
At September 30, 2000
- ---------------------
Segment assets $6,098.8 $3,427.0 $1,104.8 $1,298.8 $ (273.4) $11,656.0
At December 31, 1999
- --------------------
Segment assets $1,206.1 $6,312.6 $915.3 $1,231.3 $18.5 $9,683.8
(a) Our electric business recorded expense of $4.9 million for the three months
and nine months ended September 30, 1999 related to Hurricane Floyd. Our
power projects business recorded $6.7 million for the three months and nine
months ended September 30, 1999 for the write-off of a geothermal power
plant. Our financial investments business recorded expense of $17.3 million
for the three months and $20.9 million for the nine months ended September
30, 1999 for the write-down of its investment in Capital Re stock. Our real
estate and senior-living facilities business recorded expense of $3.4
million for the three months and nine months ended September 30, 1999 for a
write-down of certain senior-living facilities.
(b) Our electric business recorded expense of $4.2 million for the nine months
ended September 30, 2000 related to employees that elected to participate
in a Targeted Voluntary Special Early Retirement Program. In addition, our
domestic merchant energy business recorded a $15.0 million deregulation
transition cost incurred by our power marketing business. We discuss these
further in the Overview section of Management's Discussion and Analysis.
Financing Activity
- ------------------
Constellation Energy
- --------------------
As discussed on page 11, effective April 30, 1999, BGE's outstanding common
stock automatically became shares of common stock of Constellation Energy.
During the period from January 1, 2000 through the date of this report, we
issued a total of 975,300 shares of common stock, without par value, under our
Continuous Offering Program for Stock. Net proceeds were about $35.9 million.
Constellation Energy issued the following long-term notes during the period from
January 1, 2000 through the date of this report:
Date Net
Principal Issued Proceeds
--------- ------ --------
(In millions)
7 7/8% Notes due 2005 $300 4/00 $297.5
Floating Rate Notes due 2003 200 4/00 199.3
Extendible Notes due 2010 300 6/00 299.6
Floating Rate Reset Notes
due 2002 200 10/00 199.6
In June 2000, Constellation Energy arranged two revolving credit agreements
totaling $565.0 million to support our commercial paper program and for other
working capital purposes. Of this amount, $376.5 million is for short-term
financial needs and $188.5 million, which expires in three years, is for short
and long-term financial needs, including letters of credit. As of the date of
this report, letters of credit totaling $112.5 million were issued under this
facility. Also, letters of credit totaling $12.0 million were issued under other
credit facilities.
Constellation Energy has issued guarantees in an amount up to $617.3 million
related to credit facilities and contractual performance of certain of its
nonregulated subsidiaries. However, the actual subsidiary liabilities related to
these guarantees totaled $343.3 million at September 30, 2000.
13
In connection with the initiative to separate our domestic merchant energy
business from our retail services business, Constellation Energy expects to
redeem all of its currently outstanding $1.0 billion debt at or prior to the
separation. The redemption will occur through a combination of open market
purchases, tender offers, and redemption calls.
BGE and Nonregulated Businesses
- -------------------------------
In October 2000, BGE issued $200.0 million of Floating Rate Reset Notes due in
2001 with net proceeds of $199.8 million.
In June 2000, BGE arranged a $25.0 million long-term revolving credit agreement
to support its commercial paper program and for other working capital purposes.
In conjunction with the July 1, 2000 transfer of generation assets, BGE is
contingently liable for $278.0 million of the tax exempt debt assigned to
nonregulated affiliates of Constellation Energy as discussed further in the
Current Issues-Electric Competition section of Management's Discussion and
Analysis on page 20.
In the future, BGE may purchase some of its long-term debt or preference stock
in the market. This will depend on market conditions and BGE's capital
structure, including the mix of secured and unsecured debt.
Please refer to the Funding for Capital Requirements section of Management's
Discussion and Analysis on page 34 for additional information about the debt of
BGE and our nonregulated businesses.
Stock Option Program
- --------------------
In May 2000, our Board of Directors approved the issuance of non-qualified stock
options to officers and key employees as permitted under existing incentive
plans. Under the plans, the options are granted at prices not less than the
market value of the stock at the date of grant, generally become exercisable
ratably over a three-year period beginning one year from the date of grant, and
expire ten years from the date of grant. During the second quarter, we granted
2,313,000 stock options at an exercise price of $34.25.
As permitted by SFAS No. 123, Accounting for Stock-Based Compensation, we
measure our stock-based compensation in accordance with Accounting Principles
Board Opinion No. 25, Accounting for Stock Issued to Employees, and related
interpretations. Under this standard, compensation expense is measured as the
difference between the market value of our common stock and the exercise price
of the options on the grant date. Accordingly, no compensation expense was
recorded for the stock options granted in 2000.
Commitments
- -----------
Some of our nonregulated businesses have committed to contribute additional
capital and to make additional loans to some affiliates, joint ventures, and
partnerships in which they have an interest. At the date of this report, the
total amount of investment requirements committed to by our nonregulated
businesses was $218.0 million.
Environmental Matters
- ---------------------
Clean Air
- ---------
The Clean Air Act of 1990 contains two titles designed to reduce emissions of
sulfur dioxide and nitrogen oxide (NOx) from electric generating stations -
Title IV and Title I.
Title IV addresses emissions of sulfur dioxide. Compliance is required in two
phases:
o Phase I became effective January 1, 1995. We met the requirements of this
phase by installing flue gas desulfurization systems, switching fuels, and
retiring some units.
o Phase II became effective January 1, 2000. We met the compliance
requirements through a combination of switching fuels and allowance
trading.
We will meet the ongoing compliance requirements through a combination of
switching fuels and allowance trading.
Title I addresses emissions of NOx. The Maryland Department of the Environment
(MDE) issued regulations, effective October 18, 1999, which required up to 65%
NOx emissions reductions by May 1, 2000. We entered into a settlement agreement
with the MDE since we could not meet this deadline. Under the terms of the
settlement agreement, BGE will install emissions reduction equipment at two
sites by May 2002. In the meantime, we are taking steps to control NOx emissions
at our generating plants.
The Environmental Protection Agency (EPA) issued a final rule in September 1998
that required up to 85% NOx emissions reduction by 22 states including Maryland
and Pennsylvania. Maryland expects to meet the requirements of the rule by 2003.
The emissions reduction equipment installations discussed above will allow us to
meet these requirements.
14
We currently estimate that the controls needed at our generating plants to meet
the MDE's 65% NOx emission reduction requirements will cost approximately $135
million. Through the date of this report, we have spent approximately $82.6
million to meet the 65% reduction requirements. We estimate the additional cost
for the EPA's 85% reduction requirements to be approximately $35 million by the
end of 2002.
In July 1997, the EPA published new National Ambient Air Quality Standards for
very fine particulates and revised standards for ozone attainment. In 1999,
these new standards were successfully challenged in court. The EPA appealed the
1999 court rulings to the Supreme Court. In May 2000, the Supreme Court decided
to hear the EPA's appeal. While these standards may require increased controls
at our fossil generating plants in the future, implementation, if required,
would be delayed for several years. We cannot estimate the cost of these
increased controls at this time because the states, including Maryland and
Pennsylvania, still need to determine what reductions in pollutants will be
necessary to meet the EPA standards.
On August 3, 2000, we received letters from the EPA requesting us to provide
certain information under Section 114 of the federal Clean Air Act regarding
some of our electric generating plants. This information is to determine
compliance with the Clean Air Act and state implementation plan requirements,
including potential application of federal New Source Performance Standards. In
general, such standards can require the installation of additional air pollution
control equipment upon the major modification of an existing plant. We believe
our generating plants have been operated in accordance with the Clean Air Act
and the rules implementing the Clean Air Act. However, we cannot estimate the
impact of this inquiry on our generating plants, and our financial results, at
this time.
Waste Disposal
- --------------
The EPA and several state agencies have notified us that we are considered a
potentially responsible party with respect to the cleanup of certain
environmentally contaminated sites owned and operated by others. We cannot
estimate the cleanup costs for all of these sites.
We can, however, estimate that our current 15.43% share of the reasonably
possible cleanup costs at one of these sites, Metal Bank of America, a metal
reclaimer in Philadelphia, could be as much as $4.9 million higher than amounts
we have recorded as a liability on our Consolidated Balance Sheets. This
estimate is based on a Record of Decision issued by the EPA.
On July 12, 1999, the EPA notified us, along with nineteen other entities, that
we may be a potentially responsible party at the 68th Street Dump/Industrial
Enterprises Site, also known as the Robb Tyler Dump located in Baltimore,
Maryland. The EPA indicated that it is proceeding with plans to conduct a
remedial investigation and feasibility study. This site was proposed for listing
as a federal Superfund site in January 1999, but the listing has not been
finalized. Although our potential liability cannot be estimated, we do not
expect such liability to be material based on our records showing that we did
not send waste to the site.
Also, we are coordinating investigation of several sites where gas was
manufactured in the past. The investigation of these sites includes reviewing
possible actions to remove coal tar. In late December 1996, we signed a consent
order with the MDE that requires us to implement remedial action plans for
contamination at and around the Spring Gardens site, located in Baltimore,
Maryland. We submitted the required remedial action plans and they were approved
by the MDE. Based on the remedial action plans, the costs we consider to be
probable to remedy the contamination are estimated to total $47 million. We have
recorded these costs as a liability on our Consolidated Balance Sheets and have
deferred these costs, net of accumulated amortization and amounts we recovered
from insurance companies, as a regulatory asset. Because of the results of
studies at these sites, it is reasonably possible that these additional costs
could exceed the amount we recognized by approximately $14 million. We discuss
this further in Note 5 of our 1999 Annual Report on Form 10-K. Through the date
of this report, we have spent approximately $35 million for remediation at this
site.
We do not expect the cleanup costs of the remaining sites to have a material
effect on our financial results.
Our potential environmental liabilities and pending environmental actions are
described further in our 1999 Annual Report on Form 10-K in Item 1. Business -
Environmental Matters.
Nuclear Insurance
- -----------------
If there were an accident or an extended outage at either unit of the Calvert
Cliffs Nuclear Power Plant (Calvert Cliffs), it could have a substantial adverse
financial effect on us. The primary contingencies that would result from an
incident at Calvert Cliffs could include:
o physical damage to the plant,
o recoverability of replacement power costs, and
o our liability to third parties for property damage and bodily injury.
15
We have insurance policies that cover these contingencies, but the policies have
certain industry standard exclusions. Furthermore, the costs that could result
from a covered major accident or a covered extended outage at either of the
Calvert Cliffs units could exceed our insurance coverage limits.
Insurance for Calvert Cliffs and Third Party Claims
- ---------------------------------------------------
For physical damage to Calvert Cliffs, we have $2.75 billion of property
insurance from an industry mutual insurance company. If an outage at either of
the two units at Calvert Cliffs is caused by an insured physical damage loss and
lasts more than 12 weeks, we have insurance coverage for replacement power costs
up to $490.0 million per unit, provided by an industry mutual insurance company.
This amount can be reduced by up to $98.0 million per unit if an outage at both
units of the plant is caused by a single insured physical damage loss. If
accidents at any insured plants cause a shortfall of funds at the industry
mutual insurance company, all policyholders could be assessed, with our share
being up to $15.4 million.
In addition we, as well as others, could be charged for a portion of any third
party claims associated with a nuclear incident at any commercial nuclear power
plant in the country. At the date of this report, the limit for third party
claims from a nuclear incident is $9.54 billion under the provisions of the
Price Anderson Act. If third party claims exceed $200 million (the amount of
primary insurance), our share of the total liability for third party claims
could be up to $176.2 million per incident. That amount would be payable at a
rate of $20 million per year.
Insurance for Worker Radiation Claims
- -------------------------------------
As an operator of a commercial nuclear power plant in the United States, we are
required to purchase insurance to cover radiation injury claims of certain
nuclear workers. On January 1, 1998, a new insurance policy became effective for
all operators requiring coverage for current operations. Waiving the right to
make additional claims under the old policy was a condition for acceptance under
the new policy. We describe both the old and new policies below.
o Nuclear worker claims reported on or after January 1, 1998 are covered by a
new insurance policy with an annual industry aggregate limit of $200
million for radiation injury claims against all those insured by this
policy.
o All nuclear worker claims reported prior to January 1, 1998 are still
covered by the old insurance policies. Insureds under the old policies,
with no current operations, are not required to purchase the new policy
described above, and may still make claims against the old policies for the
next eight years. If radiation injury claims under these old policies
exceed the policy reserves, all policyholders could be assessed, with our
share being up to $6.3 million.
If claims under these polices exceed the coverage limits, the provisions of the
Price Anderson Act (discussed in this section) would apply.
Recoverability of Electric Fuel Costs
- -------------------------------------
Under the terms of the Restructuring Order, BGE's electric fuel rate clause was
discontinued effective July 1, 2000. In September 2000, the Maryland PSC
approved the collection of the $54.6 million accumulated difference between our
actual costs of fuel and energy and the amounts collected from customers that
were deferred (included as an asset or liability on the Consolidated Balance
Sheets and excluded from the Consolidated Statements of Income) under the
electric fuel rate clause through June 30, 2000. We will collect this
accumulated difference from customers over a twelve-month period beginning
October 2000.
California Power Purchase Agreements
- ------------------------------------
Constellation Power, Inc. and subsidiaries and Constellation Investments, Inc.
(whose power projects are managed by Constellation Power) have $297.6 million
invested in 14 projects that sell electricity in California under power purchase
agreements called "Interim Standard Offer No. 4" agreements. Under these
agreements, the projects supply electricity to utility companies at:
o a fixed rate for capacity and energy for the first 10 years of the
agreements, and
o a fixed rate for capacity plus a variable rate for energy based on the
utilities' avoided cost for the remaining term of the agreements.
Generally, a "capacity rate" is paid to a power plant for its availability to
supply electricity, and an "energy rate" is paid for the electricity actually
generated. "Avoided cost" generally is the cost of a utility's cheapest
next-available source of generation to service the demands on its system.
We use the term "transitioned" to describe when the 10-year periods for fixed
energy rates have expired for these power generation projects and they began
supplying electricity at variable rates. The two remaining projects that have
not transitioned will do so by December 2000.
16
The projects that have already transitioned to variable rates have had lower
revenues under variable rates than they did under fixed rates. Once the
remaining projects have transitioned to variable rates, we expect the revenues
from those projects also to be lower than they are under fixed rates.
We discuss these projects on page 26 of Management's Discussion and Analysis.
Other Nonregulated Businesses
- -----------------------------
In September 2000, our real estate and senior-living facilities business
converted 984,307 preferred shares of Corporate Office Properties Trust (COPT)
into approximately 1.8 million common shares of COPT. We discuss the prior COPT
transactions in Note 3 of our 1999 Annual Report on Form 10-K.
We discuss our other nonregulated businesses' activities further in the Other
Nonregulated Businesses section of Management's Discussion and Analysis on page
31.
Related Party Transactions - BGE
- --------------------------------
Income Statement
- ----------------
Under the Restructuring Order, BGE is providing standard offer service to
customers at fixed rates over various time periods during the transition period,
July 1, 2000 to June 30, 2006, for those customers that do not choose an
alternate supplier. Constellation Power Source is under contract to provide BGE
with the energy and capacity required to meet its standard offer service
obligations for the first three years of the transition period. The cost of
BGE's purchased energy from nonregulated affiliates of Constellation Energy to
meet its standard offer service obligation was $373.2 million for the quarter
and nine months ended September 30, 2000.
In addition, BGE receives charges from 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 $9.6 million for the quarter and $16.9 million for the nine months
ending September 30, 2000. These costs were not material in 1999 due to the
transfer of certain BGE employees to the holding company during that year.
Balance Sheet
- -------------
As a result of the deregulation of electric generation, BGE transferred its
generation assets to nonregulated affiliates of Constellation Energy effective
July 1, 2000. In conjunction with this transfer, Constellation Power Source
Generation, Inc. issued approximately $366 million in unsecured promissory notes
to BGE. Repayments of the notes by Constellation Power Source Generation, Inc.
will be used exclusively to service current maturities of certain BGE long-term
debt. As of September 30, 2000, $87 million of these notes are still outstanding
and will mature on March 14, 2001.
Amounts related to the corporate functions performed at the Constellation Energy
holding company and to BGE's purchases to meet its standard offer service
obligation resulted in intercompany accounts payable to Constellation Energy and
affiliates of $197.2 million at September 30, 2000. These amounts were not
material in 1999.
17
Item 2. Management's Discussion
Management's Discussion and Analysis of Financial Condition and Results of
Operations
Introduction
- ------------
On April 30, 1999, Constellation Energy(R) Group, Inc. (Constellation Energy)
became the holding company for Baltimore Gas and Electric Company (BGE(R)) and
Constellation(R) Enterprises, Inc. Constellation Enterprises was previously
owned by BGE.
Constellation Energy's subsidiaries primarily include a domestic merchant energy
business focused mostly on power marketing and merchant generation in North
America, and BGE.
This Quarterly Report on Form 10-Q is a combined report of Constellation Energy
and BGE. The consolidated financial statements of Constellation Energy include
the accounts of Constellation Energy, BGE and its subsidiaries, Constellation
Enterprises, Inc. and its subsidiaries, and Constellation Nuclear, LLC and its
subsidiaries. The consolidated financial statements of BGE include the accounts
of BGE, ComfortLink, and BGE Capital Trust I. As Constellation Enterprises and
its subsidiaries were subsidiaries of BGE prior to April 30, 1999, they are
included in the consolidated financial statements of BGE through that date.
We realigned our organization in response to the deregulation of electric
generation. In the first quarter of 2000, we combined our wholesale power
marketing business with our domestic plant development and operations to form a
domestic merchant energy business. At the same time, we revised our operating
segments to reflect those realignments as presented in the Notes to Consolidated
Financial Statements on page 12. Several additional changes occurred in
conjunction with the implementation of the Restructuring Order as described
below. We discuss the deregulation of electric generation and the Restructuring
Order in the Current Issues -- Electric Competition section on page 20.
o We formed two nonregulated subsidiaries -- Calvert Cliffs Nuclear Power
Plant, Inc. and Constellation Power Source Generation, Inc.
o Effective July 1, 2000, BGE transferred its generation assets and related
liabilities to these two new entities at book value.
o Effective July 1, 2000, we formed a nonregulated holding company,
Constellation Power Source Holdings, Inc., that includes the wholesale
power marketing and risk management activities of Constellation Power
Source,(TM) Inc., the domestic power projects of Constellation
Investments,(TM)Inc. and Constellation Power,(TM)Inc., and subsidiaries,
and the generating assets of Constellation Power Source Generation.
As a result of these changes, effective July 1, 2000, our domestic merchant
energy business includes the operations of Constellation Power Source Holdings
and the nuclear generation and consulting services of Constellation Nuclear,
(TM) LLC.
Also, effective July 1, 2000, the financial results of the electric generation
portion of our business are included in the domestic merchant energy business.
Prior to that date, the financial results of electric generation were included
in BGE's regulated electric business.
BGE remains a regulated electric and gas public utility company with a service
territory in the City of Baltimore and all or part of ten counties in Central
Maryland.
Our other nonregulated businesses include the:
o Latin American power projects of Constellation Power, and subsidiaries,
o energy products and services of Constellation Energy Source,(TM)Inc.,
o home products, commercial building systems, and residential and commercial
electric and gas retail marketing of BGE Home Products & Services,(TM)Inc.
and subsidiaries,
o general partnership, in which BGE is a partner, of District Chilled Water
General Partnership (ComfortLink(R)) that provides cooling services for
commercial customers in Baltimore,
o financial investments of Constellation Investments, and
o real estate and senior-living facilities of Constellation Real Estate
Group,(TM) Inc.
As discussed in the Subsequent Event section of the Notes to Consolidated
Financial Statements on page 11, we announced initiatives to separate our
domestic merchant energy business from our retail services business and an
investment by an affiliate of Goldman Sachs in our domestic merchant energy
business.
18
References in this report to "we" and "our" are to Constellation Energy and its
subsidiaries, collectively. Reference in this report to the "utility business"
is to BGE.
In this discussion and analysis, we explain the general financial condition and
the results of operations for Constellation Energy and BGE including:
o what factors affect our business,
o what our earnings and costs were in the periods presented,
o why earnings and costs changed between periods,
o where our earnings came from,
o how all of this affects our overall financial condition,
o what we expect our expenditures for capital projects to be in the future,
and
o where we expect to get cash for future capital expenditures.
As you read this discussion and analysis, refer to our Consolidated Statements
of Income on page 3, which present the results of our operations for the
quarters and nine months ended September 30, 2000 and 1999. We analyze and
explain the differences between periods in the specific line items of the
Consolidated Statements of Income. Our analysis is important in making decisions
about your investments in Constellation Energy and/or BGE.
Also, this discussion and analysis is based on the operation of the electric
generation portion of our utility business under rate regulation through June
30, 2000. Our electric business is changing as we have transferred our electric
generation assets and related liabilities to nonregulated subsidiaries of
Constellation Energy and we have entered into retail customer choice for
electric generation effective July 1, 2000. Accordingly, the results of
operations and financial condition described in this discussion and analysis are
not necessarily indicative of future performance.
Strategy
- --------
The change toward customer choice will significantly impact our business. In
response to this change, we regularly evaluate our strategies with two goals in
mind: to improve our competitive position, and to anticipate and adapt to
regulatory change. Prior to July 1, 2000, the majority of our earnings were from
BGE. Going forward, we expect to derive almost two-thirds of our earnings from
our domestic merchant energy business.
While BGE will continue to be regulated and deliver electricity and natural gas
through its core distribution business, our growth strategies center on the
nonregulated domestic merchant energy business with the objective of providing
new sources of earnings.
Currently, our domestic merchant energy business owns or controls 8,500
megawatts of generation. We have planned construction of 1,100 megawatts of
peaking capacity in the Mid-Atlantic/Mid-West region by the summer of 2001 and
an additional 4,300 megawatts of peaking and combined cycle production
facilities in the Mid-West and South regions are scheduled for completion in
2002 and beyond. By 2005, our domestic merchant energy business expects to own
or control approximately 30,000 megawatts.
As discussed in the Subsequent Event section of the Notes to Consolidated
Financial Statements on page 11, we announced several initiatives to advance our
growth strategies. These initiatives consist of:
o a plan to separate our domestic merchant energy business from our retail
services business,
o an agreement with an affiliate of Goldman Sachs under which it will invest
in our domestic merchant energy business, and
o a reduction in our common stock dividend effective April 2001.
In addition, we decided to exit the Latin American portion of our business as a
result of our concentration on domestic merchant energy. Currently, we are
actively seeking a buyer for the Latin American portion of our business and
expect to complete our exit strategy in 2001.
We also might consider one or more of the following strategies:
o the complete or partial separation of our transmission and distribution
functions,
o the construction or purchase of additional nuclear and non-nuclear
generation assets,
o mergers or acquisitions of utility or non-utility businesses, and
o sale of generation assets or one or more businesses.
19
With the shift toward customer choice, competition, and the growth of our
domestic merchant energy business, various factors will affect our financial
results in the future. These factors include, but are not limited to, operating
our generation assets in a deregulated market without the benefit of a fuel rate
adjustment clause, the timing and implications of deregulation in other regions
where our domestic merchant energy business will operate, the loss of revenues
due to customers choosing alternative suppliers, higher volatility of earnings
and cash flows, and increased financial requirements of our domestic merchant
energy business. Please refer to the Forward-Looking Statements section on page
37 for additional factors.
Current Issues -- Electric Competition
- --------------------------------------
Electric utilities are facing competition on various fronts, including:
o the construction of generating units to meet increased demand for
electricity,
o the sale of electricity in bulk power markets,
o competing with alternative energy suppliers, and
o electric sales to retail customers.
On April 8, 1999, Maryland enacted the Electric Customer Choice and Competition
Act of 1999 (the "Act") and accompanying tax legislation that has significantly
restructured Maryland's electric utility industry and modified the industry's
tax structure.
In the Restructuring Order discussed below, the Maryland PSC addressed the major
provisions of the Act. The accompanying tax legislation is discussed in detail
in Note 4 of our 1999 Annual Report on Form 10-K.
On November 10, 1999, the Maryland PSC issued a Restructuring Order that
resolved the major issues surrounding electric restructuring, accelerated the
timetable for customer choice, and addressed the major provisions of the Act.
The Restructuring Order also resolved the electric restructuring proceeding
(transition costs, customer price protections, and unbundled rates for electric
services) and a petition filed in September 1998 by the Office of People's
Counsel (OPC) to lower our electric base rates. The major provisions of the
Restructuring Order are discussed below.
o All customers, except a few commercial and industrial companies that have
signed contracts with BGE, can choose their electric energy supplier
beginning July 1, 2000. BGE will provide a standard offer service for
customers that do not select an alternative supplier. In either case, BGE
will continue to deliver electricity to all customers in areas
traditionally served by BGE.
o BGE's electric base rates were frozen through June 30, 2000.
o BGE reduced residential base rates by approximately 6.5%, on average about
$54 million a year, beginning July 1, 2000. These rates will not change
before July 2006.
o Commercial and industrial customers have up to four service options that
will fix electric energy rates and transition charges for a period that
generally ranges from four to six years.
o BGE's electric fuel rate clause was discontinued effective July 1, 2000.
o Electric delivery service rates are frozen for a four-year period for
commercial and industrial customers. The generation and transmission
components of rates are frozen for different time periods depending on the
service options selected by those customers.
o BGE will recover $528 million after-tax of its potentially stranded
investments and utility restructuring costs through a competitive
transition charge on customers' bills. Residential customers will pay this
charge for six years. Commercial and industrial customers will pay in a
lump sum or over the four to six-year period, depending on the service
option selected by each customer.
o Generation-related regulatory assets and nuclear decommissioning costs are
included in delivery service rates effective July 1, 2000 and will be
recovered on a basis approximating their amortization schedules prior to
July 1, 2000.
o Effective July 1, 2000, BGE unbundled rates to show separate components for
delivery service, transition charges, standard offer services (generation),
transmission, universal service, and taxes.
o Effective July 1, 2000, BGE transferred, at book value, its ten
Maryland-based fossil and nuclear power plants and its partial ownership
interest in two coal plants and a hydroelectric plant in Pennsylvania to
nonregulated subsidiaries of Constellation Energy.
20
o BGE reduced its generation assets, as discussed in Note 4 of our 1999
Annual Report on Form 10-K, by $150 million pre-tax during the period July
1, 1999 - June 30, 2000 to mitigate a portion of BGE's potentially stranded
investments.
o Universal service is being provided for low-income customers without
increasing their bills. BGE will provide its share of a statewide fund
totaling $34 million annually.
We believe that the Restructuring Order provided sufficient details of the
transition plan to competition for BGE's electric generation business to require
BGE to discontinue the application of Statement of Financial Accounting
Standards (SFAS) No. 71, Accounting for the Effects of Certain Types of
Regulation for that portion of its business. Accordingly, in the fourth quarter
of 1999, we adopted the provisions of SFAS No. 101, Regulated Enterprises -
Accounting for the Discontinuation of FASB Statement No. 71 and Emerging Issues
Task Force Consensus (EITF) No. 97-4, Deregulation of the Pricing of Electricity
- - Issues Related to the Application of FASB Statements No. 71 and 101 for BGE's
electric generation business. BGE's transmission and distribution business
continues to meet the requirements of SFAS No. 71 as that business remains
regulated. We describe the effect of applying these accounting requirements in
Note 4 of our 1999 Annual Report on Form 10-K.
Please refer to the Legal Proceedings section on page 36 for a discussion
regarding appeals of the Restructuring Order.
As a result of the deregulation of electric generation, the following occurred
effective July 1, 2000:
o BGE transferred, at book value, its nuclear generating assets, its nuclear
decommissioning trust fund, and related liabilities to Calvert Cliffs
Nuclear Power Plant, Inc. In addition, BGE transferred, at book value, its
fossil generating assets and related liabilities and its partial ownership
interest in two coal plants and a hydroelectric plant located in
Pennsylvania to Constellation Power Source Generation. In total, these
generating assets represent about 6,240 megawatts of generation capacity
with a total net book value at June 30, 2000 of approximately $2.4 billion.
o BGE assigned approximately $47 million to Calvert Cliffs Nuclear Power
Plant, Inc. and $231 million to Constellation Power Source Generation of
tax-exempt debt related to the transferred assets. Also, Constellation
Power Source Generation issued approximately $366 million in unsecured
promissory notes to BGE. Repayments of the notes by Constellation Power
Source Generation will be used exclusively to service the current
maturities of certain BGE long-term debt.
o BGE transferred equity associated with the generating assets to Calvert
Cliffs Nuclear Power Plant, Inc. and Constellation Power Source Generation,
Inc.
o The fossil fuel and nuclear fuel inventories, materials and supplies, and
certain purchased power contracts of BGE were also assumed by these
subsidiaries.
Effective July 1, 2000, BGE provides standard offer service to customers at
fixed rates over various time periods during the transition period for those
customers that do not choose an alternate supplier. In addition, the electric
fuel rate was discontinued effective July 1, 2000. Constellation Power Source
provides BGE with the energy and capacity required to meet its standard offer
service obligations for the first three years of the transition period.
Thereafter, BGE will competitively bid the energy and capacity.
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 purchased from the wholesale energy market as
necessary.
Our domestic merchant energy business is affected by weather conditions in the
different regions of North America. Typically, demand for electricity, and its
price, is higher in the summer and the winter, when weather is more extreme. All
regions of North America typically do not experience extreme weather conditions
at the same time. To date, the majority of our generation is located in the PJM
(Pennsylvania-New Jersey-Maryland) Interconnection. Accordingly, our financial
results are affected by weather in this area. However, by 2005, we expect to own
or control approximately 30,000 megawatts of generation throughout various
regions of North America.
21
Current Issues -- Regulated Businesses
- --------------------------------------
We also believe it is important to discuss factors that have a strong influence
on the performance of our regulated electric and regulated gas businesses. In
addition to electric restructuring which was discussed earlier, regulation by
the Maryland PSC, the weather, and other factors, including the condition of the
economy in our service territory influence BGE's businesses.
Regulation by the Maryland PSC
- ------------------------------
Under traditional rate regulation that continues after July 1, 2000 for BGE's
electric transmission and distribution, and gas businesses, the Maryland PSC
determines the rates we can charge our customers. Currently, BGE's rates consist
primarily of a "base rate" and a "fuel rate."
Base Rate
- ---------
The base rate is the rate the Maryland PSC allows BGE to charge its customers
for the cost of providing them service, plus a profit. BGE has both an electric
base rate and a gas base rate. Higher electric base rates apply during the
summer when the demand for electricity is higher. Gas base rates are not
affected by seasonal changes.
BGE may ask the Maryland PSC to increase base rates from time to time. The
Maryland PSC historically has allowed BGE to increase base rates to recover
increased utility plant asset costs, plus a profit, beginning at the time of
replacement. Generally, rate increases improve our utility earnings because they
allow us to collect more revenue. However, rate increases are normally granted
based on historical data and those increases may not always keep pace with
increasing costs. Other parties may petition the Maryland PSC to decrease base
rates.
On November 17, 1999, BGE filed an application with the Maryland PSC to increase
its gas base rates. On June 19, 2000, the Maryland PSC authorized a $6.4 million
annual increase in our gas base rates effective June 22, 2000.
As a result of the Restructuring Order, BGE's residential electric base rates
are frozen until 2006.
Electric delivery service rates are frozen for a four-year period for commercial
and industrial customers. The generation and transmission components of rates
are frozen for different time periods depending on the service options selected
by those customers.
Fuel Rate
- ---------
Through June 30, 2000, we charged our electric customers separately for the fuel
we used to generate electricity (nuclear fuel, coal, gas, or oil) and for the
net cost of purchases and sales of electricity. We charged the actual cost of
these items to the customer with no profit to us. If these fuel costs went up,
the Maryland PSC permitted us to increase the fuel rate.
Under the Restructuring Order, BGE's electric fuel rate was frozen until July 1,
2000, at which time the fuel rate clause was discontinued. We deferred the
difference between our actual costs of fuel and energy and what we collected
from customers under the fuel rate through June 30, 2000.
In September 2000, the Maryland PSC approved the collection of the $54.6 million
accumulated difference between our actual costs of fuel and energy and the
amounts collected from customers that were deferred under the electric fuel rate
clause through June 30, 2000. We will collect this accumulated difference from
customers over a twelve-month period beginning October 2000. Effective July 1,
2000, earnings are affected by the changes in the cost of fuel and energy.
We charge our gas customers separately for the natural gas they purchase from
us. The price we charge for the natural gas is based on a market based rates
incentive mechanism approved by the Maryland PSC. We discuss market based rates
in more detail in the Gas Cost Adjustments section on page 30 and in Note 1 of
our 1999 Annual Report on Form 10-K.
Weather
- -------
Weather conditions can have a great impact on BGE's results for interim periods
primarily due to the impact on sales volumes and commodity prices. This means
that results for interim periods do not necessarily represent results to be
expected for the year.
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
30.
We measure the weather's effect using "degree days." A degree day is the
difference between the average daily actual temperature and a baseline
temperature of 65 degrees. Cooling degree days result when the average daily
actual temperature exceeds the 65 degree baseline. Heating degree days result
when the average daily actual temperature is less than the baseline.
22
During the cooling season, hotter weather is measured by more cooling degree
days and results in greater demand for electricity to operate cooling systems.
During the heating season, colder weather is measured by more heating degree
days and results in greater demand for electricity and gas to operate heating
systems.
We show the number of heating degree days in the quarter and nine months ended
September 30, 2000 and 1999, and the percentage change in the number of degree
days between these periods in the following table:
Quarter Ended Ended Nine Months Ended
September 30 September 30
------------------ ------------------
2000 1999 2000 1999
------- ------ ------ ------
Heating degree days... 142 75 2,959 2,981
Percent change
from prior period 89.3% (0.7)%
Cooling degree days... 445 629 714 832
Percent change
from prior period (29.3)% (14.2)%
Other Factors
- -------------
Other factors, aside from weather, impact the demand for electricity and gas in
our regulated businesses. These factors include the "number of customers" and
"usage per customer" during a given period. We use these terms later in our
discussions of regulated electric and gas operations. In those sections, we
discuss how these and other factors affected electric and gas sales during the
periods presented.
The number of customers in a given period is affected by new home and apartment
construction and by the number of businesses in our service territory. Under the
Restructuring Order, BGE's electric customers can become delivery service
customers only and can purchase their electricity from other sources. We will
collect a delivery service charge to recover the fixed costs for the service we
provide. The remaining electric customers will receive standard offer service
from BGE at the fixed rates provided by the Restructuring Order. Usage per
customer refers to all other items impacting customer sales that cannot be
measured separately. These factors include the strength of the economy in our
service territory. When the economy is healthy and expanding, customers tend to
consume more electricity and gas. Conversely, during an economic downtrend, our
customers tend to consume less electricity and gas.
Current Issues - 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.
Current Issues - Calvert Cliffs License Extension
- -------------------------------------------------
On March 23, 2000, the Nuclear Regulatory Commission (NRC) approved a 20-year
license extension for both units of Calvert Cliffs, extending the license for
Unit 1 to 2034 and for Unit 2 to 2036.
On April 11, 2000 the United States Court of Appeals for the District of
Columbia Circuit, in National Whistleblowers Center v. Nuclear Regulatory
Commission and Baltimore Gas and Electric Company, upheld the NRC's denial of
the Center's motion to intervene in BGE's license renewal proceeding. The NRC
had denied the Center's motion to intervene for failing to file timely
contentions. The Center has filed a petition for certiorari, a request to hear
an appeal, with the U.S. Supreme Court.
Current Issues - Regional Transmission Organizations
- ----------------------------------------------------
In December 1999, the FERC issued Order 2000, amending its regulations under the
Federal Power Act to advance the formation of Regional Transmission
Organizations (RTOs). The regulations require that each public utility that
owns, operates, or controls facilities for the transmission of electric energy
in interstate commerce make certain filings with respect to forming and
participating in a RTO. FERC also identified the minimum characteristics and
functions that a transmission entity must satisfy in order to be considered a
RTO.
According to the Order, a public utility that is a member of an existing
transmission entity that has been approved by FERC as in conformance with the
Independent System Operator (ISO) principles set forth in the FERC Order No.
888, such as BGE, through its membership in the PJM must make a filing no later
than January 15, 2001. While not required until 2001, PJM and the joint
transmission owners, including BGE, made the filing on October 11, 2000. That
filing explained the extent to which PJM met the minimum characteristics and
functions of a RTO and explained its plans to conform to these characteristics
and functions.
As a member of the PJM, an existing ISO, BGE does not expect to be materially
impacted by the Order. However, BGE, along with other members of the PJM, is
appealing certain aspects of the Order. We cannot determine the full impact of
the Order at this time.
23
Results of Operations for the Quarter and Nine Months Ended September 30, 2000
- -------------------------------------------------------------------------------
Compared with the Same Periods of 1999
- --------------------------------------
In this section, we discuss our earnings and the factors affecting them. We
begin with a general overview, then separately discuss earnings for our
operating segments. Changes in fixed charges, income taxes, and other income are
discussed in the aggregate for all segments in the Consolidated Nonoperating
Income and Expenses section on page 32.
Overview
- --------
Total Earnings Per Share of Common Stock
- ----------------------------------------
Quarter Ended Nine Months Ended
September 30 September 30
----------------- -----------------
2000 1999 2000 1999
-------- -------- -------- --------
Earnings before
nonrecurring charges
included in
operations:
Domestic merchant
energy .............. $ .87 $ .14 $1.10 $ .34
Regulated electric..... .10 1.05 .65 1.73
Regulated gas.......... (.03) - .12 .14
Other nonregulated..... .04 (.06) (.01) (.05)
-------- -------- -------- --------
Total earnings per
share before
nonrecurring
charges included
in operations ....... .98 1.13 1.86 2.16
Nonrecurring charges
included in
operations:
Deregulation
transition
cost............... - - (.10) -
TVSERP............... - - (.03) -
Hurricane Floyd
expenses .......... - (.03) - (.03)
Write-off of
power project...... - (.05) - (.05)
Write-down of
financial
investment......... - (.12) - (.14)
Write-down of
senior-living
facilities......... - (.02) - (.02)
-------- -------- -------- --------
Earnings per share ..... $ .98 $ .91 $1.73 $1.92
======== ======== ======== ========
Earnings for the periods presented below reflect a significant shift in earnings
from the regulated electric business to the domestic merchant energy business as
a result of the transfer of BGE's electric generation assets to nonregulated
subsidiaries on July 1, 2000 in accordance with the Restructuring Order. We
discuss the Restructuring Order in more detail in Current Issues - Electric
Competition section on page 20.
Quarter Ended September 30, 2000
- --------------------------------
Our total earnings for the quarter ended September 30, 2000 increased $11.4
million, or $.07 per share, compared to the same period of 1999. However, our
total earnings before nonrecurring charges decreased $20.9 million or $.15 per
share mostly due to extremely mild summer weather in 2000. We also recognized
$26.0 million, or almost one-half, of the annual impact of a 6.5% annual
residential rate reduction that was effective July 1, 2000. This decrease was
partially offset by a $37.5 million deferral of electric revenues recorded in
September 1999 associated with the deregulation of our electric generation
business that had a negative impact in that year. We did not have a similar
deferral in 2000. We also had higher earnings from our other nonregulated
businesses in the third quarter of 2000 compared to the same period of 1999.
In addition, we recorded the following nonrecurring charges in operations during
the third quarter of 1999:
o $4.9 million after-tax, or $.03 per share, of expenses related to Hurricane
Floyd,
o a $6.7 million after-tax, or $.05 per share, write-off of a geothermal
power project,
o a $17.3 million after-tax, or $.12 per share, write-down of a financial
investment, and
o a $3.4 million after-tax, or $.02 per share, write-down of certain
senior-living facilities.
In the following sections, we discuss our earnings by business segment in
greater detail.
Nine Months Ended September 30, 2000
- ------------------------------------
Our total earnings for the nine months ended September 30, 2000 decreased $27.7
million, or $.19 per share, compared to the same period of 1999. Our total
earnings before nonrecurring charges decreased $44.4 million or $.30 per share
mostly due to the $75.0 million, or $45.4 million after-tax, amortization of the
regulatory asset recorded for the reduction of BGE's generation plant during the
first half of 2000 and the large impact of the 6.5% annual residential rate
reduction reflected in the third quarter. This decrease was partially offset by
the $37.5 million deferral of electric revenues in 1999. In addition, we
recorded the following nonrecurring charges in operations:
o a $15.0 million after-tax, or $.10 per share, deregulation transition cost
in June 2000 to a third party incurred by our power marketing business to
provide BGE's standard offer service requirements,
24
o a $4.2 million after-tax, or $.03 per share, expense during the first and
second quarters of 2000 for BGE employees that elected to participate in a
Targeted Voluntary Special Early Retirement Program (TVSERP),
o $4.9 million after-tax, or $.03 per share, of expenses related to Hurricane
Floyd in 1999,
o a $6.7 million after-tax, or $.05 per share, write-off of a geothermal
power project in 1999,
o a $20.9 million after-tax, or $.14 per share, write-down of a financial
investment in 1999, and
o a $3.4 million after-tax, or $.02 per share, write-down of certain
senior-living facilities in 1999.
Domestic Merchant Energy Business
- ---------------------------------
Our domestic merchant energy business engages primarily in power marketing and
domestic power generation. We describe these businesses in more detail in our
1999 Annual Report on Form 10-K in Item 1. Business -- Diversified Businesses.
As discussed in the Current Issues -- Electric Competition section on page 20,
our domestic merchant energy business was significantly impacted by the July 1,
2000 implementation of customer choice in Maryland. At that time, BGE's
generating assets became part of our nonregulated domestic merchant energy
business, and Constellation Power Source began selling to BGE the energy and
capacity required to meet its standard offer service obligations for the first
three years of the transition period.
Constellation Power Source will obtain the energy and capacity to supply BGE's
standard offer service obligations from affiliates that own Calvert Cliffs and
BGE's former fossil plants, supplemented with energy purchased from the
wholesale energy market as necessary. Constellation Power Source will also
manage our wholesale market price risk.
Our earnings are exposed to the risks of the competitive wholesale electricity
market to the extent that Constellation Power Source has to purchase energy
and/or capacity to meet obligations to supply power to BGE at market prices or
costs, respectively, which may approach or exceed BGE's standard offer service
rates. If the price of obtaining energy in the wholesale market exceeds the
fixed standard offer service price, our earnings would be adversely affected. We
are also affected by operational risk, that is, the risk that a generating plant
will not be available to produce energy when the energy is required. Imbalances
in demand and supply can occur not only because of plant outages, but also
because of transmission constraints, or extreme temperatures (hot or cold)
causing demand to exceed available supply.
We cannot estimate the impact of the increased financial risks associated with
customer choice. However, these financial risks could have a material impact on
our financial results.
In addition, effective July 1, 2000, under the terms of separate agreements,
domestic merchant energy business revenues include 90% of the competitive
transition charges BGE collects from its customers (CTC revenues) and the
portion of its revenues providing for decommissioning costs.
Earnings
- --------
Quarter Ended Nine Months Ended
September 30 September 30
----------------- -----------------
2000 1999 2000 1999
-------- -------- -------- --------
(In millions, except per share amounts)
Revenues................ $495.6 $66.3 $628.9 $173.7
Operating expenses...... 221.7 40.7 312.3 87.8
Depreciation and
amortization....... 38.6 1.5 41.9 3.6
Taxes other than
income taxes....... 13.1 - 13.1 -
-------- -------- -------- --------
Operating income........ $222.2 $24.1 $261.6 $82.3
======== ======== ======== ========
Net income.............. $130.9 $12.2 $150.2 $43.6
======== ======== ======== ========
Earnings per share...... $ .87 $ .09 $ 1.00 $ .29
======== ======== ======== ========
Above amounts include intercompany transactions eliminated in our Consolidated
Financial Statements.
Revenues
- --------
During the quarter ended September 30, 2000, domestic merchant energy revenues
increased $429.3 million compared to the same period of 1999 mostly because of:
o a $373.2 million increase related to providing BGE the energy and capacity
required to meet its standard offer service obligation effective July 1,
2000, and
o a $59.3 million increase related to CTC and decommissioning revenues
included in the domestic merchant energy business effective July 1, 2000.
During the nine months ended September 30, 2000, domestic merchant energy
revenues increased $455.2 million compared to the same period of 1999 mostly
because of the increase in revenues associated with the implementation of
customer choice as discussed above and higher revenues from our power marketing
and domestic generation businesses.
Power marketing revenues increased during the nine months ended September 30,
2000 compared to the same period of 1999 mostly because of higher transaction
volumes. These higher volumes were offset partially by lower margins.
25
Our domestic generation business revenues increased during the nine months ended
September 30, 2000 compared to the same period of 1999 mostly because of the
gain recognized on the termination of an operating arrangement and the sale of
certain subsidiaries. In April 2000, Constellation Operating Services, Inc.
(COSI), a subsidiary of Constellation Power, Inc., ended its exclusive
arrangement with Orion Power Holdings, Inc. to operate Orion's facilities. Orion
purchased from COSI the four subsidiary companies formed to operate power plants
owned by Orion. This increase was offset partially by lower revenues associated
with our California power purchase agreements discussed below.
Mark-to-Market Accounting
- -------------------------
Constellation Power Source uses the mark-to-market method of accounting. We
discuss the mark-to-market method of accounting and Constellation Power Source's
activities in more detail in Note 1 of our 1999 Annual Report on Form 10-K.
As a result of the nature of its business activities, Constellation Power
Source's revenue and earnings will fluctuate. We cannot predict these
fluctuations, but the effect on our revenues and earnings could be material. The
primary factors that cause these fluctuations are:
o the number and size of new transactions,
o the magnitude and volatility of changes in commodity prices and interest
rates, and
o the number and size of open commodity and derivative positions
Constellation Power Source holds or sells.
Constellation Power Source's management uses its best estimates to determine the
fair value of commodity and derivative positions it holds and sells. These
estimates consider various factors including closing exchange and
over-the-counter price quotations, time value, volatility factors, and credit
exposure. However, it is possible that future market prices could vary from
those used in recording assets and liabilities from power marketing and trading
activities, and such variations could be material. Assets and liabilities from
energy trading activities (as shown in our Consolidated Balance Sheets beginning
on page 4) increased at September 30, 2000 compared to December 31, 1999 because
of business growth during the period.
California Power Purchase Agreements
- ------------------------------------
Our domestic generation business has $297.6 million invested in 14 projects that
sell electricity in California under power purchase agreements called "Interim
Standard Offer No. 4" agreements.
Under these agreements, the electricity rates change from fixed rates to
variable rates beginning in 1996 and continuing through 2000. The projects which
already have had rate changes have lower revenues under variable rates than they
did under fixed rates. When the remaining projects transition to variable rates,
we expect their revenues also to be lower than they are under fixed rates.
At the date of this report, 12 projects had already transitioned to variable
rates. The remaining two projects will transition in December 2000.
Our power projects business continues to pursue alternatives for some of these
projects including:
o repowering the projects to reduce operating costs,
o changing fuels to reduce operating costs,
o renegotiating the power purchase agreements to improve the terms,
o restructuring financing to improve existing terms, and selling its
ownership interests in the projects.
We evaluate the carrying amount of our investment in these projects for
impairment using the methodology discussed in Note 1 of our 1999 Annual Report
of Form 10-K. Constellation Power's management uses its best estimates to
determine if there has been an impairment of these investments and considers
various factors including forward price curves for energy, fuel costs, and
operating costs. However, it is possible that future estimates of market prices
and project costs could vary from those used in evaluating these assets, and the
impact of such variations could be material.
We also describe these projects and the transition process in the Notes to
Consolidated Financial Statements on page 16.
Operating Expenses
- ------------------
During the quarter ended September 30, 2000, domestic merchant energy operating
expenses increased $181.0 million compared to the same period of 1999 mostly
because of increases of $102.6 million in fuel costs and $79.2 million in
operations and maintenance costs. These fuel and operations and maintenance
costs were associated with the generation plants that were transferred from BGE
effective July 1, 2000.
26
During the nine months ended September 30, 2000, domestic merchant energy
operating expenses increased $224.5 million compared to the same period of 1999
mostly because of:
o the transfer of fuel, operations, and maintenance costs from BGE effective
July 1, 2000, as discussed on page 26,
o a $10.2 million write-off of a geothermal power project in August 1999 by
our domestic power projects business. This write-off occurred because the
expected future cash flow from the project was less than the investment in
the project due to the declining water temperature of the geothermal
resource used by the plant for production,
o a $24.0 million deregulation transition cost in June 2000 to a third party
incurred by our power marketing business to provide BGE's standard offer
service requirements, and
o an increase in operating expenses at our power marketing business due to
the growth of the business.
Depreciation and Amortization Expense
- -------------------------------------
Domestic merchant energy depreciation and amortization expense increased $37.1
million for the quarter and $38.3 million for the nine months ended September
30, 2000 compared to the same periods of 1999 mostly because of $36.8 million of
expenses associated with the generation plants that were transferred from BGE
effective July 1, 2000.
Taxes Other than Income Taxes
- -----------------------------
During the quarter and nine months ended September 30, 2000, domestic merchant
energy taxes other than income taxes increased $13.1 million compared to the
same periods of 1999 because of $12.9 million of taxes other than income taxes
associated with the generation plants that were transferred from BGE effective
July 1, 2000.
Regulated Electric Business
- ---------------------------
As previously discussed, our regulated electric business was significantly
impacted by the July 1, 2000 implementation of customer choice. These changes
include BGE's generating assets and related liabilities becoming part of our
nonregulated domestic merchant energy business on that date.
Earnings
- --------
Quarter Ended Nine Months Ended
September 30 September 30
----------------- -----------------
2000 1999 2000 1999
-------- -------- -------- --------
(In millions, except per share amounts)
Electric revenues....... $598.4 $691.4 $1,688.4 $1,737.9
Electric fuel and
purchased energy... 388.3 130.0 632.4 376.2
Operations and
maintenance........ 62.0 146.3 384.7 468.5
Depreciation and
amortization....... 52.0 78.3 276.7 227.0
Taxes other than
income taxes....... 30.5 59.5 121.0 149.2
-------- -------- -------- --------
Operating income........ $65.6 $277.3 $273.6 $517.0
======== ======== ======== ========
Net income.............. $15.4 $152.3 $93.2 $253.4
======== ======== ======== ========
Earnings per share...... $ .10 $1.02 $ .62 $1.70
======== ======== ======== ========
Above amounts include intercompany transactions eliminated in our Consolidated
Financial Statements.
Electric Revenues
- -----------------
The changes in electric revenues in 2000 compared to 1999 were caused by:
Quarter Ended Nine Months Ended
September 30 September 30
2000 vs. 1999 2000 vs. 1999
----------------- -----------------
(In millions)
Electric system
sales volumes ........ $(28.5) $ 4.5
Rates .................. (75.5) (62.9)
--------- ---------
Total change in electric
revenues from electric
system sales ......... (104.0) (58.4)
Interchange and
other sales ......... (24.9) (30.2)
Other .................. 35.9 39.1
--------- ---------
Total change in
electric revenues ... $(93.0) $(49.5)
========= =========
Electric System Sales Volumes
- -----------------------------
"Electric system sales volumes" are sales to customers in our service territory
at rates set by the Maryland PSC. These sales do not include interchange sales
and sales to others.
The percentage changes in our electric system sales volumes, by type of
customer, in 2000 compared to 1999 were:
Quarter Ended Nine Months Ended
September 30 September 30
2000 vs. 1999 2000 vs. 1999
--------------- ------------------
Residential............. (10.8)% (0.7)%
Commercial.............. 0.2 3.8
Industrial.............. 13.2 4.1
27
During the quarter ended September 30, 2000, we sold less electricity to
residential customers due to extremely mild summer weather. We sold about the
same amount of electricity to commercial customers. We sold more electricity to
industrial customers mostly because usage by Bethlehem Steel (our largest
customer) was higher in 2000 because of a 1999 shut down for a planned upgrade
to their facilities that temporarily reduced their electricity consumption in
that year.
During the nine months ended September 30, 2000, we sold about the same amount
of electricity to residential customers due to the extremely mild summer weather
being substantially offset by warmer spring and early summer weather, an
increased number of customers, and higher usage per customer. We sold more
electricity to commercial customers mostly due to higher usage per customer and
an increased number of customers. We sold more electricity to industrial
customers due to the increase in usage by Bethlehem Steel, offset partially by
lower usage by other industrial customers.
Rates
- -----
Prior to July 1, 2000, our rates primarily consisted of an electric base rate
and an electric fuel rate. Effective July 1, 2000, BGE discontinued its electric
fuel rate and unbundled its rates to show separate components for delivery
service, transition charges, standard offer services (generation), transmission,
universal service, and taxes. In addition, BGE's rates were frozen in total
except for the implementation of a residential base rate reduction totaling
approximately $54 million annually. Under the terms of the intercompany
agreements whereby BGE obtains the energy and capacity to meet its standard
offer service obligation, 90% of the CTC revenues BGE collects and the portion
of its revenues providing for decommissioning costs, are included in revenues of
the domestic merchant energy business effective July 1, 2000.
During the quarter ended September 30, 2000, rate revenues decreased compared to
the same period of 1999 mostly because we recognized $26.0 million, or almost
one-half of the 6.5% annual residential rate reduction, and $59.3 million of CTC
and decommissioning revenues are included in the domestic merchant energy
business.
During the nine months ended September 30, 2000, rate revenues decreased $62.9
million compared to the same periods of 1999 as a result of the rate reduction
and transfer of revenues discussed above, offset partially by higher rate
revenues during the first half of 2000.
Interchange and Other Sales
- ---------------------------
"Interchange and other sales" are sales in the PJM energy market and to others.
The PJM is an ISO that also operates a regional power pool with members that
include many wholesale market participants, as well as BGE, and other utility
companies. Prior to the implementation of customer choice, BGE sold energy to
PJM members and to others after it had satisfied the demand for electricity in
its own system.
Effective July 1, 2000, BGE no longer engages in interchange sales and these
activities are included in our domestic merchant energy business which results
in the decrease in interchange and other sales for the quarter and nine months
ended September 30, 2000 compared to the same periods of 1999. In addition, BGE
had lower interchange and other sales during the first half of 2000 when
increased demand for system sales reduced the amount of energy it had available
for off-system sales.
Other
- -----
During the quarter and nine months ended September 30, 2000, other revenues
increased compared to the same periods of 1999 mostly because of a $37.5 million
deferral of electric revenues recorded in September 1999, which had a negative
impact in that year. This deferral was recorded on the basis that as of
September 30, 1999 these revenues were subject to refund pending the approval of
the Restructuring Order by the Maryland PSC at that time.
Electric Fuel and Purchased Energy Expenses
- -------------------------------------------
Quarter Ended Nine Months Ended
September 30 September 30
----------------- -----------------
2000 1999 2000 1999
-------- -------- -------- --------
(In millions)
Actual costs............ $388.3 $191.8 $642.1 $454.7
Net deferral of
costs under
electric fuel
rate clause......... - (61.8) (9.7) (78.5)
-------- -------- -------- --------
Total electric
fuel and
purchased energy
expenses............ $388.3 $130.0 $632.4 $376.2
======== ======== ======== ========
Actual Costs
- ------------
During the quarter and nine months ended September 30, 2000, our actual costs of
fuel and purchased energy were higher compared to the same periods of 1999
mostly because of the implementation of customer choice.
As discussed in the Current Issues -- Electric Competition section on page 20,
effective July 1, 2000, BGE transferred its generating assets to, and began
purchasing substantially all of the energy and capacity required to provide
electricity to standard offer service customers from, nonregulated affiliates of
Constellation Energy. For the quarter and nine months ended September 30, 2000,
the cost of energy BGE purchased from nonregulated affiliates of Constellation
Energy was $373.2 million. The higher amount paid for purchased energy is offset
by lower operations and maintenance, depreciation, taxes, and other costs at BGE
as a result of no longer owning and operating the transferred electric
generation plants.
28
Prior to July 1, 2000, BGE's purchased fuel and energy costs only included
actual costs of fuel to generate electricity (nuclear fuel, coal, gas, or oil)
and electricity we bought from others.
Electric Fuel Rate Clause
- -------------------------
Prior to July 1, 2000, we deferred 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.
During the quarter and nine months ended September 30, 2000, the net deferral of
costs under the electric fuel rate clause decreased compared to the same periods
of 1999 due to the discontinuation of the fuel rate clause effective July 1,
2000.
We discuss the accumulated difference between our actual costs and what we
collected through June 30, 2000 in the Recoverability of Electric Fuel Costs
section of the Notes to Consolidated Financial Statements on page 16.
Electric Operations and Maintenance Expenses
- --------------------------------------------
During the quarter ended September 30, 2000, regulated electric operations and
maintenance expenses decreased $84.3 million compared to 1999 mostly because
effective July 1, 2000, $79.2 million of costs were no longer incurred by this
business segment. These costs were associated with the electric generation
assets that were transferred to the domestic merchant energy business. In
addition, 1999 operations and maintenance expenses include approximately $7.5
million of costs associated Hurricane Floyd that had a negative impact in that
quarter.
During the nine months ended September 30, 2000, regulated electric operations
and maintenance expenses decreased $83.8 million compared to 1999 mostly due to
the absence of $79.2 million of costs associated with the transfer of the
electric generation assets. Also, 1999 operations and maintenance expenses
include costs associated with Hurricane Floyd and a major winter ice storm
earlier that year. This decrease is partially offset by the $7.0 million of
expense recognized in 2000 for electric business employees that elected to
participate in the TVSERP.
Electric Depreciation and Amortization Expense
- ----------------------------------------------
During the quarter ended September 30, 2000, regulated electric depreciation and
amortization expense decreased $26.3 million compared to 1999 mostly because of
the absence of $36.8 million of depreciation and amortization expense associated
with the transfer of the generation assets to the domestic merchant energy
business. This was partially offset by higher amortization expense associated
with our electric generation regulatory assets.
During the nine months ended September 30, 2000, regulated electric depreciation
and amortization expense increased $49.7 million compared to 1999 mostly because
of the $75.0 million amortization of the regulatory asset for the reduction in
generation plant provided for in the Restructuring Order and higher amortization
associated with other generation regulatory assets. This was partially offset by
the absence of $36.8 million of depreciation and amortization expense associated
with the transfer of the generation assets.
Electric Taxes Other Than Income Taxes
- --------------------------------------
Regulated electric taxes other than income taxes decreased $29.0 million for the
quarter and $28.2 million for the nine months ended September 30, 2000 compared
to the same periods of 1999. This was mostly due to comprehensive changes to the
tax laws under the Electric Customer Choice and Competition Act of 1999. The
comprehensive tax law changes are discussed further in Note 4 of our 1999 Annual
Report on Form 10-K. In addition, regulated electric taxes other than income
taxes reflect the absence of $12.9 million of taxes other than income taxes
associated with the generation assets that were transferred to the domestic
merchant energy business effective July 1, 2000.
Regulated Gas Business
- ----------------------
Earnings
- --------
Quarter Ended Nine Months Ended
September 30 September 30
----------------- -----------------
2000 1999 2000 1999
-------- -------- -------- --------
(In millions, except per share amounts)
Gas revenues............ $90.1 $62.9 $377.8 $340.1
Gas purchased for resale 48.2 21.3 192.0 156.4
Operations and
maintenance........ 26.2 20.8 73.1 69.1
Depreciation and
amortization....... 11.3 10.2 35.5 34.4
Taxes other than
income taxes....... 5.0 4.6 25.0 25.2
-------- -------- -------- --------
Operating income (loss). $(0.6) $6.0 $52.2 $55.0
======== ======== ======== ========
Net income (loss)....... $(4.6) $(0.7) $18.1 $21.5
======== ======== ======== ========
Earnings per share...... $(.03) $ - $.12 $.14
======== ======== ======== ========
Above amounts include intercompany transactions eliminated in our Consolidated
Financial Statements.
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.
29
Gas Revenues
- ------------
The changes in gas revenues in 2000 compared to 1999 were caused by:
Quarter Ended Nine Months Ended
September 30 September 30
2000 vs. 1999 2000 vs. 1999
----------------- -----------------
(In millions)
Gas system
sales volumes ....... $ 3.9 $ 11.5
Base rates ............. 0.7 0.2
Weather normalization .. (1.9) (5.4)
Gas cost adjustments ... 8.8 (4.4)
--------- --------
Total change in gas
revenues from gas
system sales.......... 11.5 1.9
Off-system sales........ 16.4 36.1
Other .................. (0.7) (0.3)
--------- -------
Total change in
gas revenues ........ $ 27.2 $ 37.7
========= ========
Gas System Sales Volumes
- ------------------------
The percentage changes in our gas system sales volumes, by type of customer, in
2000 compared to 1999 were:
Quarter Ended Nine Months Ended
September 30 September 30
2000 vs. 1999 2000 vs. 1999
----------------- -----------------
Residential............... 3.0% 1.5%
Commercial................ 17.6 7.5
Industrial................ 3.4 4.2
During the quarter ended September 30, 2000, we sold more gas to residential
customers compared to the same period of 1999 due mostly to an increased number
of customers. We sold more gas to commercial customers mostly because of higher
usage per customer offset partially by fewer customers. We sold more gas to
industrial customers mostly because of an increase in the number of customers.
During the nine months ended September 30, 2000, we sold more gas to residential
and commercial customers compared to the same period of 1999 due to higher usage
per customer and an increased number of customers. This was partially offset by
milder winter weather. We sold more gas to industrial customers mostly because
of higher usage by Bethlehem Steel and other industrial customers, and an
increased number of customers.
Base Rates
- ----------
During the quarter and nine months ended September 30, 2000, base rate revenues
increased slightly compared to the same periods of 1999 mostly because on June
19, 2000, the Maryland PSC authorized a $6.4 million annual increase in our base
rates effective June 22, 2000.
Weather Normalization
- ---------------------
The Maryland PSC allows us to record a monthly adjustment to our gas revenues to
eliminate the effect of abnormal weather patterns on our gas system sales
volumes. This means our monthly gas revenues are based on weather that is
considered "normal" for the month and, therefore, are not affected by actual
weather conditions.
Gas Cost Adjustments
- --------------------
We charge our gas customers for the natural gas they purchase from us using gas
cost adjustment clauses set by the Maryland PSC as described in Note 1 of our
1999 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, and does not significantly
impact earnings.
Delivery service customers, including Bethlehem Steel, are not subject to the
gas cost adjustment clauses because we are not selling gas to them. We charge
these customers fees to recover the fixed costs for the transportation service
we provide. These fees are the same as the base rate charged for gas sales and
are included in gas system sales volumes.
During the quarter ended September 30, 2000, gas cost adjustment revenues
increased compared to the same period of 1999 mostly because we sold gas at a
higher price.
During the nine months ended September 30, 2000, gas cost adjustment revenues
decreased compared to the same period of 1999 mostly because we sold less gas to
non-delivery service customers. This was partially offset by a higher price of
gas sold.
Off-System Sales
- ----------------
Off-system gas sales are low-margin direct sales of gas to wholesale suppliers
of natural gas outside our service territory. Off-system gas sales, which occur
after we have satisfied our customers' demand, are not subject to gas cost
adjustments. The Maryland PSC approved an arrangement for part of the margin
from off-system sales to benefit customers (through reduced costs) and the
remainder to be retained by BGE (which benefits shareholders). Changes in
off-system sales do not significantly impact earnings.
During the quarter and nine months ended September 30, 2000, revenues from
off-system gas sales increased compared to the same periods of 1999 mostly
because we sold more gas off-system at a higher price.
30
Gas Purchased For Resale Expenses
- ---------------------------------
Actual costs include the cost of gas purchased for resale to our customers and
for off-system sales. Actual costs do not include the cost of gas purchased by
delivery service customers.
During the quarter and nine months ended September 30, 2000, our gas costs
increased compared to the same periods of 1999 mostly because we bought more gas
for off-system sales and all of the gas purchased was at a higher price.
Gas Operations and Maintenance Expenses
- ---------------------------------------
During the quarter and nine months ended September 30, 2000, gas operations and
maintenance expenses increased compared to the same periods of 1999 mostly
because of timing of corporate administrative and general expenses allocated to
our business segments.
Gas Depreciation and Amortization Expense
- -----------------------------------------
During the quarter and nine months ended September 30, 2000, gas depreciation
and amortization expense was about the same compared to the same periods of
1999.
Other Nonregulated Businesses
- -----------------------------
Earnings
- --------
Quarter Ended Nine Months Ended
September 30 September 30
2000 1999 2000 1999
------- -------- -------- --------
(In millions, except per share amounts)
Revenues................ $187.7 $207.1 $557.4 $635.1
Operating expenses...... 156.2 233.0 496.7 637.1
Depreciation and
amortization........ 5.8 2.8 16.6 9.0
Taxes other than
income taxes........ 1.0 1.0 3.0 2.8
-------- -------- -------- --------
Operating income (loss). $24.7 $(29.7) $41.1 $(13.8)
======== ======== ======== ========
Net income (loss)....... $5.7 $(27.7) $(2.3) $(31.6)
======== ======== ======== ========
Earnings per share...... $.04 $(.20) $(.01) $(.21)
======== ======== ======== ========
Above amounts include intercompany transactions eliminated in our Consolidated
Financial Statements.
During the quarter ended September 30, 2000, earnings from our other
nonregulated businesses increased compared to the same period of 1999 mostly
because of higher earnings from our financial investments business. Our
financial investments business had higher earnings due to an increase in its
market performance and a 1999 write-down of a financial investment that had a
negative impact in that year. In addition, our energy products and services
business had higher gross margins from its gas trading activities.
During the nine months ended September 30, 2000, earnings from our other
nonregulated businesses increased compared to the same period of 1999 mostly
because of higher earnings from our financial investments and energy products
and services businesses. In addition, in 1999, we wrote-down a financial
investment and certain senior-living facilities, which had negative impacts in
that year. These increases were partially offset by lower earnings from our
Latin American business primarily due to increased operating expenses in
Guatemala.
In December 1999, we decided to exit the Latin American portion of our power
projects business as part of our strategy to improve our competitive position.
We discuss our strategy further in the Strategy section on page 19.
In June 1999, our financial investments business wrote-down its investment in
Capital Re stock by $3.6 million after-tax, or $.02 per share. In September
1999, our financial investments business wrote-down the investment by an
additional $17.3 million after-tax, or $.12 per share. These write-downs were
recorded to reflect the valuation for the exchange of its shares of common stock
in Capital Re for common stock of ACE Limited during these periods. This
exchange is discussed further in our 1999 Annual Report on Form 10-K.
In September 1999, our real estate and senior-living facilities business
wrote-down certain senior-living facilities by $3.4 million after-tax, or $.02
per share, related to the announcement of the sale of those facilities.
Most of Constellation Real Estate Group's real estate and senior-living projects
are in the Baltimore-Washington corridor. The area has had a surplus of
available land in recent years and as a result these projects have been
economically hurt.
Constellation Real Estate's projects have continued to incur carrying costs and
depreciation over the years. Additionally, this business has been charging
interest payments to expense rather than capitalizing them for some undeveloped
land where development activities have stopped. These carrying costs,
depreciation, and interest expenses have decreased earnings and are expected to
continue to do so.
Cash flow from real estate and senior-living operations has not been enough to
make the monthly loan payments on some of these projects. Cash shortfalls have
been covered by cash obtained from the cash flows of, or additional borrowings
by, other nonregulated subsidiaries.
31
We consider market demand, interest rates, the availability of financing, and
the strength of the economy in general when making decisions about our real
estate and senior-living projects. If we were to decide to sell our projects, we
could have write-downs. In addition, if we were to sell our projects in the
current market, we would have losses which could be material, although the
amount of the losses is hard to predict. Depending on market conditions, we
could also have material losses on any future sales.
Our current real estate and senior-living strategy is to hold each project until
we can realize a reasonable value for it. Under accounting rules, we are
required to write down the value of a project to market value in either of two
cases. The first is if we change our intent about a project from an intent to
hold to an intent to sell and the market value of that project is below book
value. The second is if the expected cash flow from the project is less than the
investment in the project.
Consolidated Nonoperating Income and Expenses
- ---------------------------------------------
Fixed Charges
- -------------
During the quarter and nine months ended September 30, 2000, fixed charges
increased compared to the same periods of 1999 mostly because we had more debt
outstanding.
Income Taxes
- ------------
During the quarter and nine months ended September 30, 2000, our total income
taxes increased compared to the same periods of 1999 mostly because we had
higher taxable income from our nonregulated businesses and an increase in state
and local taxes as a result of comprehensive changes to these laws. This
increase was partially offset by lower taxable income at BGE. We discuss the
comprehensive tax law changes in Note 4 of our 1999 Annual Report on Form 10-K.
Financial Condition
- -------------------
Cash Flows
- ----------
Nine Months Ended
September 30
-----------------
2000 1999
-------- --------
(In millions)
Cash provided by (used in):
Operating Activities $588.8 $483.5
Investing Activities (728.4) (441.8)
Financing Activities 97.3 (159.0)
During the nine months ended September 30, 2000, we generated more cash from
operations compared to the same period in 1999 mostly because of changes in
working capital requirements.
During the nine months ended September 30, 2000, we used more cash for investing
activities compared to the same period in 1999 mostly due to an increase in
investments in new generation facilities. In addition, our real estate and
senior-living facilities business received less cash compared to the same period
of 1999, due to the sale of a project in 1999. We did not have a similar sale in
2000.
During the nine months ended September 30, 2000, we had more cash from financing
activities compared to the same period of 1999 mostly because we issued more
long-term debt and common stock. This was partially offset by repayment of our
long-term debt that matured.
Security Ratings
- ----------------
Independent credit-rating agencies rate Constellation Energy and BGE's
fixed-income securities. The ratings indicate the agencies' assessment of each
company's ability to pay interest, distributions, dividends, and principal on
these securities. These ratings affect how much it will cost each company to
sell these securities. The better the rating, the lower the cost of the
securities to each company when they sell them. Constellation Energy and BGE's
securities ratings at the date of this report are:
Standard Moody's
& Poors Investors Fitch
Rating Group Service IBCA
-------------- ----------- ----------
Constellation Energy
- --------------------
Unsecured Debt A- A3 A-
BGE
- ---
Mortgage Bonds AA- A1 A+
Unsecured Debt A A2 A
Trust Originated
Preferred Securities
and Preference Stock A- "a2" A-
32
Capital Resources
- -----------------
Our business requires a great deal of capital. Our estimated annual amounts for
the years 2000 through 2002, are shown in the table below.
We will continue to have cash requirements for:
o working capital needs including the payments of interest, distributions,
and dividends,
o capital expenditures, and
o the retirement of debt and redemption of preference stock.
Capital requirements for 2000 through 2002 include estimates of funding for
existing and anticipated projects. We continuously review and modify those
estimates. Actual requirements may vary from the estimates included in the table
below because of a number of factors including:
o regulation, legislation, and competition,
o BGE load requirements,
o environmental protection standards,
o the type and number of projects selected for development,
o the effect of market conditions on those projects,
o the cost and availability of capital, and
o the availability of cash from operations.
Our estimates are also subject to additional factors. Please see the
Forward-Looking Statements section on page 37.
Effective July 1, 2000, all of BGE's generation assets were transferred to
nonregulated subsidiaries of Constellation Energy. The discussion and table for
capital requirements below include these generation assets as part of the
utility's regulated electric business through June 30, 2000. After that date,
the capital requirements are included in the domestic merchant energy business.
Calendar Year Estimates
2000 2001 2002
--------- --------- --------
(In millions)
Nonregulated Capital Requirements:
- ----------------------------------
Investment requirements:
Domestic Merchant Energy $803* $ 1,241 $ 1,077
Other 37 48 41
--------- --------- --------
Total investment requirements 840 1,289 1,118
Retirement of long-term debt 575 446 7
--------- --------- --------
Total nonregulated capital requirements 1,415 1,735 1,125
Utility Capital Requirements:
- -----------------------------
Construction expenditures (excluding AFC):
Regulated Electric:
Generation (including nuclear fuel) 94 - -
Transmission and distribution 177 177 171
--------- --------- --------
Total regulated electric 271 177 171
Regulated Gas 56 56 52
Common 23 26 26
--------- --------- --------
Total construction expenditures 350 259 249
Retirement of long-term debt and redemption of
preference stock 122 194 147
--------- --------- --------
Total utility capital requirements 472 453 396
--------- --------- --------
Total capital requirements $1,887 $2,188 $1,521
========= ========= ========
* Effective July 1, 2000, includes approximately $110 million for electric
generation and nuclear fuel formerly part of BGE's regulated electric business.
33
Capital Requirements
- --------------------
Domestic Merchant Energy Business
- ---------------------------------
Our domestic merchant energy business will require additional funding for
growing its power marketing business and developing and acquiring power
projects.
Our domestic merchant energy business investment requirements include the
planned construction of 1,100 megawatts of peaking capacity in the
Mid-Atlantic/Mid-West region by the summer of 2001 and an additional 4,300
megawatts of peaking and combined cycle production facilities scheduled for
completion in 2002 and beyond in the Mid-West and South regions. Longer range,
our plans are to own or control approximately 30,000 megawatts of generation
capacity by 2005. For further information see the Strategy section on page 19.
Electric Generation
- -------------------
Electric construction expenditures for our regulated electric business include
improvements to generating plants and costs for replacing the steam generators
at Calvert Cliffs through June 30, 2000. Thereafter, these expenditures are
reflected in our domestic merchant energy business.
In March 2000, we received the license extension from the NRC that extends our
operating licenses to 2034 for Unit 1 and 2036 for Unit 2 as discussed in the
Current Issues - Calvert Cliffs License Extension section on page 23. If we do
not replace the steam generators, we will not be able to operate these units
through our operating licenses period. We expect the steam generator replacement
to occur during the 2002 refueling outage for Unit 1 and during the 2003
refueling outage for Unit 2. We estimate these Calvert Cliffs' costs to be:
o $ 38 million in 2000,
o $ 63 million in 2001,
o $ 91 million in 2002, and
o $ 60 million in 2003.
Additionally, our estimates of future electric generation construction
expenditures include the costs of complying with Environmental Protection Agency
(EPA) and State of Maryland nitrogen oxides emissions (NOx) reduction
regulations as follows:
o $ 55 million in 2000,
o $ 55 million in 2001, and
o $ 8 million in 2002.
We discuss the NOx regulations and timing of expenditures in the Environmental
Matters section of the Notes to Consolidated Financial Statements on page 14.
Electric Transmission and Distribution, and Gas
- -----------------------------------------------
Regulated electric transmission and distribution, and gas construction
expenditures primarily include new business construction needs and improvements
to existing facilities.
Funding for Capital Requirements
- --------------------------------
Domestic Merchant Energy Business
- ---------------------------------
Funding for the expansion of our domestic merchant energy business is expected
from internally generated funds, commercial paper issuances, long-term debt, and
other financing instruments by Constellation Energy and its subsidiaries, and
from time to time equity contributions from Constellation Energy.
In addition, on October 23, 2000 we announced initiatives designed to advance
our growth strategies in the domestic merchant energy business as discussed in
the Subsequent Event section in the Notes to Consolidated Financial Statements
on page 11. As part of these initiatives, our domestic merchant energy business
expects to initially reinvest its earnings and not pay a dividend to fund its
growth.
At September 30, 2000, Constellation Energy has a commercial paper program where
it can issue up to $500 million in short-term notes to fund its nonregulated
businesses. To support its commercial paper program, Constellation Energy
maintains two revolving credit agreements totaling $565 million, of which one
facility can also issue letters of credit. In addition, Constellation Energy has
access to interim lines of credit as required from time to time to support its
outstanding commercial paper.
BGE
- ---
Funding for utility capital expenditures is expected from internally generated
funds, commercial paper issuances, available capacity under credit facilities,
the issuance of long-term debt, trust securities, or preference stock, and/or
from time to time equity contributions from Constellation Energy.
At September 30, 2000, FERC authorized BGE to issue up to $700 million of
short-term borrowings, including commercial paper. In addition, BGE maintains
$183 million in annual committed bank lines of credit and has $25 million in
bank revolving credit agreements to support the commercial paper program. In
addition, BGE has access to interim lines of credit as required from time to
time to support its outstanding commercial paper.
34
Other Nonregulated Businesses
- -----------------------------
BGE Home Products & Services may meet capital requirements through sales of
receivables. ComfortLink has a revolving credit agreement totaling $50 million
to provide liquidity for short-term financial needs.
If we can get a reasonable value for our real estate projects, senior-living
facilities, and other investments, additional cash may be obtained by selling
them. Our ability to sell or liquidate assets will depend on market conditions,
and we cannot give assurances that these sales or liquidations could be made. We
discuss the real estate and senior-living facilities business and market
conditions in the Other Nonregulated Businesses section on page 31.
Other Matters
- -------------
Environmental Matters
- ---------------------
We are subject to federal, state, and local laws and regulations that work to
improve or maintain the quality of the environment. If certain substances were
disposed of or released at any of our properties, whether currently operating or
not, these laws and regulations require us to remove or remedy the effect on the
environment. This includes Environmental Protection Agency Superfund sites. You
will find details of our environmental matters in the Environmental Matters
section of the Notes to Consolidated Financial Statements beginning on page 14
and in our 1999 Annual Report on Form 10-K in Item 1. Business - Environmental
Matters. These details include financial information. Some of the information is
about costs that may be material.
Accounting Standards Issued
- ---------------------------
In June 2000, the FASB issued Statement of Financial Accounting Standards (SFAS)
No. 138, Accounting for Certain Derivative Instruments and Certain Hedging
Activities, that amends certain provisions of SFAS No. 133, Accounting for
Derivative Instruments and Hedging Activities and addresses a limited number of
implementation issues related to SFAS No. 133.
In July 1999, the FASB issued SFAS No. 137 that delays the effective date for
SFAS No. 133 by one year. Therefore, we must adopt the provisions of SFAS No.
133 in our financial statements for the quarter ended March 31, 2001.
We are evaluating the implications of SFAS Nos. 133 and 138, but have not
determined the effects on our financial results. However, SFAS Nos. 133 and 138
will not significantly impact our power marketing business as this business uses
mark-to-market accounting.
Item 3. Quantitative and Qualitative Disclosures About Market Risk
We discuss the following information related to our market risk:
o risk associated with the purchase and sale of energy in a deregulated
environment as discussed in the Current Issues - Electric Competition
section of Management's Discussion and Analysis on page 20,
o financing activities in the Notes to Consolidated Financial Statements on
page 13, and
o activities of our power marketing business in the Domestic Merchant Energy
Business section of Management's Discussion and Analysis beginning on page
25.
35
PART II. OTHER INFORMATION
Item 1. Legal Proceedings
Employment Discrimination
- -------------------------
Miller v. Baltimore Gas and Electric Company, et al. - This action was filed on
September 20, 2000 in the U.S. District Court for the District of Maryland.
Besides BGE, Constellation Energy Group, Constellation Nuclear and Calvert
Cliffs Nuclear Power Plant are also named defendants. The action seeks class
certification for approximately 150 past and present employees and alleges
racial discrimination at Calvert Cliffs Nuclear Power Plant. The amount of
damages is unspecified, however the plaintiffs seek back and front pay, along
with compensatory and punitive damages. We believe this case is without merit.
However, we cannot predict the timing, or outcome, of it or its possible effect
on our, or BGE's, financial results.
Moore v. Constellation Energy Group - This action was filed on October 23, 2000
in the U.S. District Court for the District of Maryland by an employee alleging
employment discrimination. Besides Constellation Energy, BGE and Constellation
Holdings, Inc. are also named defendants. The Equal Employment Opportunity
Commission has previously concluded that it was unable to establish a violation
of law. The plaintiff seeks, among other things, unspecific monetary damages and
back pay. We believe this case is without merit.
Asbestos
- --------
Since 1993, we have been involved in several actions concerning asbestos. The
actions are based upon the theory of "premises liability," alleging that we knew
of and exposed individuals to an asbestos hazard. The actions relate to two
types of claims.
The first type is direct claims by individuals exposed to asbestos. We described
these claims in BGE's Report on Form 8-K filed August 20, 1993. We are involved
in these claims with approximately 70 other defendants. Approximately 530
individuals that were never employees of BGE each claim $6 million in damages
($2 million compensatory and $4 million punitive). These claims were filed in
the Circuit Court for Baltimore City, Maryland in the summer of 1993. We do not
know the specific facts necessary to estimate our potential liability for these
claims. The specific facts we do not know include:
o the identity of our facilities at which the plaintiffs allegedly worked as
contractors,
o the names of the plaintiff's employers, and
o the date on which the exposure allegedly occurred.
To date, 27 of these cases were settled for amounts that were not significant.
The second type is claims by one manufacturer -- Pittsburgh Corning Corp. (PCC)
- -- against us and approximately eight others, as third-party defendants. On
April 17, 2000, PCC declared bankruptcy and we do not expect PCC to prosecute
this claim.
These claims relate to approximately 1,500 individual plaintiffs and were filed
in the Circuit Court for Baltimore City, Maryland in the fall of 1993. To date,
about 350 cases have been resolved, all without any payments by BGE. We do not
know the specific facts necessary to estimate our potential liability for these
claims. The specific facts we do not know include:
o the identity of our facilities containing asbestos manufactured by the
manufacturer,
o the relationship (if any) of each of the individual plaintiffs to us,
o the settlement amounts for any individual plaintiffs who are shown to have
had a relationship to us, and
o the dates on which/places at which the exposure allegedly occurred.
Until the relevant facts for both types of claims are determined, we are unable
to estimate what our liability, if any, might be. Although insurance and hold
harmless agreements from contractors who employed the plaintiffs may cover a
portion of any awards in the actions, our potential liability could be material.
Restructuring Order
- -------------------
In early December 1999, the Mid-Atlantic Power Supply Association (MAPSA),
Trigen-Baltimore Energy Corporation and Sweetheart Cup Company, Inc. filed
appeals of the Restructuring Order, which were consolidated in the Baltimore
City Circuit Court. MAPSA also filed a motion to delay implementation of the
Restructuring Order, pending a decision on the merits of the appeals by the
court.
On April 21, 2000, the Circuit Court dismissed MAPSA's appeal based on a lack of
standing (the right of a party to bring a lawsuit to court) and denied its
motion for a delay of the Restructuring Order. However, MAPSA filed an appeal of
this decision. On May 24, 2000, the Circuit Court dismissed both the Trigen and
Sweetheart Cup appeals.
MAPSA subsequently filed several appeals with the Maryland Court of Special
Appeals, the Maryland Court of Appeals, and the Baltimore City Circuit Court.
The effect of the appeals was to delay the implementation of customer choice in
BGE's service territory.
36
However, on August 4, 2000, the delay was rescinded and BGE retroactively
adjusted its rates as if customer choice had been implemented July 1, 2000.
On September 29, 2000, the Baltimore City Circuit Court issued an order
upholding the Restructuring Order.
On October 27, 2000, MAPSA filed an appeal with the Maryland Court of Special
Appeals challenging the September 29, 2000 order issued by the Circuit Court. We
believe that this petition is without merit. However, we cannot predict the
timing, or outcome, of this case, which could have a material adverse effect on
our, and BGE's, financial results.
Asset Transfer Order
- --------------------
On July 6, 2000, MAPSA and Shell Energy LLC filed, in the Circuit Court for
Baltimore City, a petition for review and a delay of the Maryland PSC's order
approving the transfer of BGE's generation assets issued on June 19, 2000. The
Court denied MAPSA's request for a delay on August 4, 2000, and after a hearing
on the petition on August 23, 2000 issued an order on September 29, 2000
upholding the Maryland PSC's order on the asset transfer. On October 27, 2000,
MAPSA filed an appeal with the Maryland Court of Special Appeals challenging the
September 29, 2000 order issued by the Circuit Court. We also believe that this
petition is without merit. However, we cannot predict the timing, or outcome, of
this case, which could have a material adverse effect on our, and BGE's,
financial results.
Item 5. Other Information
Forward-Looking Statements
- --------------------------
We make statements in this report that are considered forward-looking statements
within the meaning of the Securities Exchange Act of 1934. Sometimes these
statements will contain words such as "believes," "expects," "intends," "plans,"
and other similar words. These statements are not guarantees of our future
performance and are subject to risks, uncertainties and other important factors
that could cause our actual performance or achievements to be materially
different from those we project. These risks, uncertainties, and factors
include, but are not limited to:
o general economic, business, and regulatory conditions,
o energy supply and demand,
o competition,
o federal and state regulations,
o availability, terms, and use of capital,
o nuclear and environmental issues,
o weather,
o implications of the Restructuring Order issued by the Maryland PSC,
including the outcome of MAPSA's appeal,
o commodity price risk,
o operating our generation assets in a deregulated market without the benefit
of a fuel rate adjustment clause,
o loss of revenue due to customers choosing alternative suppliers,
o higher volatility of earnings and cash flows,
o increased financial requirements of our nonregulated subsidiaries,
o inability to recover all costs associated with providing electric retail
customers service during the electric rate freeze period, and
o implications from the transfer of BGE's generation assets and related
liabilities to nonregulated subsidiaries of Constellation Energy, including
the outcome of an appeal of the Maryland PSC's Order regarding the transfer
of generation assets.
Given these uncertainties, you should not place undue reliance on these
forward-looking statements. Please see the other sections of this report and our
other periodic reports filed with the SEC for more information on these factors.
These forward-looking statements represent our estimates and assumptions only as
of the date of this report.
37
Item 6. Exhibits and Reports on Form 8-K
(a) Exhibit No. 3 By-laws of Constellation Energy Group, Inc.
Exhibit No. 12(a) Constellation Energy Group, Inc. Computation of
Ratio of Earnings to Fixed Charges.
Exhibit No. 12(b) Baltimore Gas and Electric Company Computation
of Ratio of Earnings to Fixed Charges and
Computation of Ratio of Earnings to Combined
Fixed Charges and Preferred and Preference
Dividend Requirements.
Exhibit No. 27(a) Constellation Energy Group, Inc. Financial Data
Schedule.
Exhibit No. 27(b) Baltimore Gas and Electric Company Financial
Data Schedule.
(b) Reports on Form 8-K for the quarter ended September 30, 2000:
Date Filed Items Reported
July 7, 2000 Item 2. Acquisition or Disposition of Assets
Item 7. Financial Statements and Exhibits
38
SIGNATURE
---------------------------
Pursuant to the requirements of the Securities Exchange Act of 1934, each
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
CONSTELLATION ENERGY GROUP, INC.
--------------------------------
(Registrant)
BALTIMORE GAS AND ELECTRIC COMPANY
----------------------------------
(Registrant)
Date: November 14, 2000 /s/ D. A. Brune
- ------------------------ ----------------------------------
D. A. Brune, Vice President on behalf of each
Registrant and as Principal Financial Officer
of each Registrant
39