ML052010322
| ML052010322 | |
| Person / Time | |
|---|---|
| Site: | Nine Mile Point  |
| Issue date: | 07/08/2005 |
| From: | Leonard M Constellation Energy Group |
| To: | Document Control Desk, Office of Nuclear Reactor Regulation |
| References | |
| -RFPFR, NMP1L 1964 | |
| Download: ML052010322 (197) | |
Text
.. Constellation Energy P.O. Box 63 Lycoming, NY 13093 Nine Mile Point Nuclear Station July 8, 2005 NMP1L 1964 U.S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, D.C. 20555-0001
SUBJECT:
Nine Mile Point Units 1 and 2 Docket Nos. 50-220 and 50-410 - -.- -
Facility Operating License Nos. DPR andNPF-69 2004 Annual Financial Reports of Constellation Energy and Long Island Power Authority Gentlemen:
Pursuant to 10 CFR 50.71(b), enclosed are copies of the 2004 'Annual Financial Reports of Constellation Energy and Long Island Power Authority;.' -
Very truly yours, M. Steven Leonard
- General Supervisor Licensing MSLJRF/sac Enclosures
-. t -
cc: Mr. S. J. Collins, NRC Regional Administrator, Region-I (without Enclosures)
Mr. G. K. Hunegs, NRC Senior Resident Inspector (without Enclosures)
Mr. T. G. Colburn, Senior Project Manager, NRR (2 copies, without Enclosures)
- ..-...H ID
LONG ISLAND POWER AUTHORITY (A Component Unit of The State of New York)
Basic Financial Statements December 31, 2004 and 2003 (With Independent Auditors' Report Thereon)
LONG ISLAND POWER AUTHORITY (A Component Unit of The State of New York)
Basic Financial Statements Table of Contents Page Section 1 Independent Auditors' Report I Management's Discussion and Analysis 2 Basic Financial Statements:
Balance Sheets 13 Statements of Revenues, Expenses, and Changes in Net Assets 15 Statements of Cash flows 16 Notes to Basic Financial Statements 17 Section 2 Report on Internal Control over Financial Reporting and on Compliance and Other Matters Based on an Audit of Financial Statements Performed in Accordance with Government Auditing Standards 56
KPMG LLP Suite 200 1305 Walt Whitman Road Melville, NY 11747-4302 Independent Auditors' Report The Board of Trustees Long Island Power Authority:
We have audited the balance sheets, statements of revenues, expenses, and changes in net assets, and statements of cash flows of the Long Island Power Authority (Authority), a component unit of the State of New York, as of and for the years then ended December 31, 2004 and 2003, which collectively comprise the Authority's basic financial statements. These financial statements are the responsibility of the Authority's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the United States of America and the standards applicable to financial audits contained in Government Auditing Standards, issued by the Comptroller General of the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Authority's internal control over financial reporting. Accordingly, we express no such opinion. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of the Authority as of December 31, 2004 and 2003, and the changes in its financial position and its cash flows for the years then ended in conformity with accounting principles generally accepted in the United States of America.
In accordance with Government Auditing Standards, we have also issued a report dated March 21, 2005 on our consideration of the Authority's internal control over financial reporting and on our tests of its compliance with certain provisions of laws, regulations, contracts, and grant agreements and other matters. The purpose of that report is to describe the scope and of our testing of internal control over financial reporting and compliance and the results of that testing, and not to provide an opinion on the internal control over financial reporting or on compliance. That report is an integral part of an audit performed in accordance with Government Auditing Standardsand should be considered in assessing the results of our audit.
The accompanying management's discussion and analysis on pages 2 through 12 is not a required part of the basic financial statements but is supplementary information required by accounting principles generally accepted in the United States of America. We have applied certain limited procedures, which consisted principally of inquiries of management regarding the methods of measurement and presentation of the required supplementary information. However, we did not audit the information and express no opinion on it.
March 21, 2005 KPMG LLP. a U.S. &'Aod bbilty p~rship, b the U.S.
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LONG ISLAND POWER AUTHORITY (A Component Unit of The State of New York)
Management's Discussion and Analysis Years ended December 31, 2004 and 2003 Overview of the Financial Statements This report consists of three parts: management's discussion and analysis, the basic financial statements, and the notes to the financial statements.
The financial statements provide summary information about the Authority's overall financial condition. The notes provide explanation and more details about the contents of the financial statements.
The Authority is considered a special-purpose government engaged in business-type activities and follows financial reporting for enterprise funds. The Authority's financial statements are prepared in accordance with generally accepted accounting principles (GAAP) as prescribed by the Governmental Accounting Standards Board (GASB). In accordance with GASB standards, the Authority has elected to comply with all authoritative pronouncements applicable to nongovernmental entities (i.e. pronouncements of the Financial Accounting Standards Board) that do not conflict with GASB pronouncements.
2 (Continued)
LONG ISLAND POWER AUTHORITY (A Component Unit of The State of New York)
Management's Discussion and Analysis Years ended December 31, 2004 and 2003 The following is a summary of the Authority's financial information for 2004, 2003, and 2002 (thousands of dollars):
Balance Sheet Summary December 31.
2004 2003 2002 Assets:
Current assets:
Cash, cash equivalents and investments $ 412,968 $ 417,987 $ 610,326 Other current assets 369,636 328,929 319,294 Noncurrent assets:
Utility plant, net 3,540,103 3,390,387 3,041,699 Promissory notes receivable 155,425 155,425 605,247 Nonutility property and other investments 120,213 72,192 75,324 Deferred charges 180,149 120,102 110,053 Regulatory assets 876,357 957,540 693,082 Acquisition adjustment, net 3,192,620 3,305,300 3,417,981 Total assets $ 8,847,471 S 8,747,862 $ 8,873,006 Liabilities and net assets:
Current liabilities $ 765,504 S 802,228 $ 764,418 Noncurrent liabilities:
Long-term debt 6,865,277 6,835,943 7,267,657 Capital lease obligation 772,800 721,630 538,619 Other noncurrent liabilities 412,270 376,441 313,565 Total liabilities 8,815,851 8,736,242 8,884,259 Net assets (deficit):
Capital assets net of related debt (634,292) (566,082) (583,359)
Unrestricted 665,912 577,702 572,106 Total net assets (deficit) 31,620 11,620 (11,253)
Total liabilities and net assets $ 8,847,471 $ 8,747,862 $ 8,873,006 3 (Continued)
LONG ISLAND PONWER AUTHORITY (A Component Unit of The State of New York)
Management's Discussion and Analysis Years ended December 31, 2004 and 2003 Summary of Revenues, Expenses, and Changes in Net Assets Yea ir ended December 31 e2, 34 2003 _ 2002 Electric revenue $ 2,853,837 $ 2,583,603 $ 2,459,210 Operating expenses:
Operations - fuel and purchased power 1,386,907 1,076,969 924,778 Operations and maintenance 691,937 733,655 767,217 General and administrative 40,962 44,875 49,780 Depreciation and amortization 229,316 230,085 220,654 Payments in lieu of taxes 215,312 213,382 218,156 Total operating expenses 2,564,434 2,298,966 2,180,585 Operating income 289,403 284,637 278,625 Other income, net 47,248 53,988 52,204 Interest charges (316,651) (318,625) (310,717)
Change in net assets before cumulative effect of change in accounting principle 20,000 20,000 20,112 Cumulative effect of change in accounting principle 2,873 Change in net assets 20,000 22,873 20,112 Net assets (deficit) - beginning of year 11,620 (11,253) (31,365)
Net assets (deficit) - end of year $ 31,620 $ 11,620 $ (11,253)
Excess of Revenues over Expenses The revenues in excess of expenses for the twelve months ended December 31, 2004, 2003, and 2002 were
$20 million.
Revenue Revenue for the year ended December 31, 2004, increased approximately $270 million when compared to the similar period in 2003. The increase is primarily attributable to system load growth totaling $24 million, higher recoveries of excess fuel costs totaling $239 million, and the impact of the August 2003 blackout which caused a revenue loss in 2003 estimated at $7 million. Weather is estimated to have positively affected revenue by
$1 million relative to the weather experienced in 2003. Such increases were partially offset by lower nonsystem revenue of approximately $1 million.
4 (Continued)
LONG ISLAND POWER AUTHORITY (A Component Unit of The State of New York)
Management's Discussion and Analysis Years ended December 31, 2004 and 2003 Revenue for the year ended December 31, 2003, increased approximately $124 million when compared to the similar period in 2002. The increase is primarily attributable to system load growth totaling $49 million and higher recoveries of excess fuel costs totaling $96 million, partially offset by the effects of weather totaling
$17 million. In 2002, weather contributed positively to overall revenue, whereas in 2003, weather had no impact on revenue, as LIPA experienced normal weather over that 12-month period. Nonsystem revenue decreased approximately $4 million, primarily due to lower sales of ancillary services to the New York Independent System Operator (NYISO) for sales of installed capacity (ICAP) and lower wheeling revenue.
Fuel and Purchased Power Costs LIPA's tariff includes a fuel recovery provision - the Fuel and Purchased Power Cost Adjustment (FPPCA).
During 2003, the FPPCA was modified to allow LIPA to recover from customers amounts incurred for fuel and purchased power beyond those included in base rates (Excess Fuel Costs) in the period incurred, as opposed to a deferral method. This modification was fully implemented on January 1, 2004, and accordingly, in 2004. LIPA recovered an amount of Excess Fuel Costs necessary to achieve revenue in excess of expenses of $20 million annually.
Effective with the Board's adoption of the 2004 budget in mid-February, the FPPCA surcharge was increased by an annual rate of 4.5% and, as a result of the continuing increases in fuel and purchased power costs, the Authority increased the surcharge by an additional annual rate of 5.0% effective June 8, 2004, and by another 1.0% effective October 1, 2004. These increases were necessary to comply with the modified FPPCA mechanism to ensure the $20 million of excess revenue over expenses by year-end.
During the year ended December 31, 2004, approximately $425 million of current year Excess Fuel Costs were billed to customers through the FPPCA, and no amounts were deferred for future recovery. During the year ended December 31, 2003, approximately $74 million of current year Excess Fuel Costs had been billed to customers through the FPPCA, and approximately $365 million was deferred for collection over the 10-year period that began January 1, 2004.
For the year ended December 31, 2004, fuel and purchased power expense increased approximately
$310 million. This increase is due in part to higher recoveries of excess fuel costs totaling $239 million, higher sales volumes of approximately S6 million, and higher currently recognized fuel costs totaling approximately
$65 million. Of the remaining excess fuel costs, LIPA applied $36 million of previously deferred credits (amounts owed to customers) to mitigate the impact of future surcharges.
After eliminating the accounting effects of the FPPCA, fuel and purchased power costs in 2004 increased by approximately $94 million when compared to the year ended December 31, 2003. Approximately $6 million is attributable to increased sales for the 2004 period compared to 2003, and the balance is attributable to increased fuel and purchased power prices.
For the year ended December 31, 2003, fuel and purchased power expense increased approximately
$152 million. This increase is primarily the result of higher recoveries of excess fuel costs totaling approximately S96 million, higher sales volumes of approximately $35 million, lower credits derived from derivative transactions totaling approximately $18 million, and lower credits resulting from off-system sales profits totaling approximately $3 million.
5 (Continued)
LONG ISLAND POWER AUTHORITY (A Component Unit of The State of New York)
Management's Discussion and Analysis Years ended December 31, 2004 and 2003 After eliminating the effects of the FPPCA, fuel and purchased power costs in 2003 increased by approximately
$327 million when compared to the year ended December 31, 2002. Approximately $35 million is attributable to increased sales for the 2003 period compared to 2002, and the balance is attributable to increased fuel and purchased power prices.
Operations and Maintenance Expense (O&M)
O&M decreased approximately $42 million for the year ended December 31, 2004, compared to the similar period in 2003 primarily due to lower MSA costs totaling approximately $19 million, lower clean energy expenses totaling approximately S9 million, one-time recognition in 2003, of LIPA's $5 million contribution to the Shoreham bill credits as required by the Shoreham Property Tax Settlement Agreement (LIPA had no such funding in 2004), lower storm cost accruals totaling approximately $12 million and lower costs associated with renting temporary emergency stand-by generators totaling approximately $1 million. Partially offsetting these decreases was increased customer accounts expenses of approximately S2 million, and $2 million related to the settlement of the Cross Sound Cable dispute.
O&M decreased approximately $34 million for the year ended December 31, 2003 when compared to the similar period in 2002. This decrease is attributable to decreased costs of renting temporary emergency stand-by generators totaling approximately S26 million, lower clean energy program costs totaling approximately
$15 million, the absence of costs similar to those incurred in 2003 associated with the accelerated completion of certain generating facilities totaling approximately $5 million, and lower Nine Mile Point 2 (NMP2) costs primarily due to the write down of inventory of approximately $4 million in 2002.
These decreases were partially offset by a $5 million charge related to the Shoreham Property Tax Settlement Agreement; the recognition of approximately $4 million related to the accretion of an Asset Retirement Obligation (ARO) as required under Financial Accounting Standards Board Statement No: 143 Accounting for Asset Retirement Obligation; and increased storm damage, repair and restoration costs totaling approximately S7 million.
General and Administrative Expenses (G&A)
General and administrative expenses decreased for the year ended December 31, 2004, approximately S4 million due primarily to decreased consulting costs related to forensic auditing services of approximately $3 million. The remaining decrease is due to lower insurance costs totaling approximately $I million.
For the year ended December 31, 2003, G&A expenses decreased approximately $5 million when compared to the similar period of 2003 due to lower charges related to claims for injuries and damages partially offset by the increased consulting fees associated with forensic auditing and energy risk management and fuel pricing activities.
Depreciation and Amortization For the year ended December 31, 2004, depreciation and amortization decreased approximately SI million.
During 2003, an adjustment totaling approximately $6 million was recognized in conjunction with the adoption of the accounting for asset retirement obligations. Partially offsetting that decrease of $6 million is higher utility plant balances in 2004 when compared to 2003 resulting in approximately $5 million higher depreciation expense.
6 (Continued)
LONG ISLAND POWER AUTHORITY (A Component Unit of The State of New York)
Management's Discussion and Analysis Years ended December 31, 2004 and 2003 For the year ended December 31, 2003, depreciation and amortization increased approximately $9 million when compared to the similar period of 2002. Approximately $6 million of that increase is related to an adjustment to nuclear decommissioning accruals resulting from the adoption of the accounting for asset retirement obligations.
The remaining increase is due to higher utility plant balances in 2003 when compared to 2002.
Payments in Lieu of Taxes For the year ended December 31, 2004, payments in lieu of taxes (PILOTs) increased approximately $2 million due to increased property taxes totaling approximately $6 million. This increase was partially offset by decreased revenue taxes (due to lower tax rates) totaling approximately $4 million.
For the year ended December 31, 2003, PILOTs decreased approximately S5 million, primarily as a result of a S12 million decrease in revenue taxes (due to lower tax rates). This decrease was partially offset by higher property taxes and the recognition of new PILOTs attributable to the new merchant-owned generating facilities under contract to LIPA, that became operational in the summer of 2003.
Other Income, Net For the year ended December 31, 2004, other income decreased approximately $7 million. This decrease was the result of lower investment income of approximately $2 million due to lower investment balances, and lower emissions credit income totaling approximately S9 million. These decreases were partially offset by interest received on New York Independent System Operator (NYISO) prior months' re-bills totaling approximately S3 million and higher carrying charges of approximately $1 million on the Shoreham property tax settlement regulatory asset.
For the year ended December 31, 2003, other income increased approximately S2 million compared to last year due primarily to an increase in the sale of emission credits totaling approximately $5 million. This increase was partially offset by a decrease in investment income as a result of lower investment balances combined with lower interest rates.
Interest Charges and Credits For the year ended December 31, 2004, interest charges and credits decreased approximately $2 million resulting from lower carrying charge expenses on deferred credits and lower deferred loss amortizations totaling approximately $7 million. This decrease was partially offset by higher interest on long term debt totaling approximately $3 million, due to higher average debt outstanding, and further offset by lower credits from allowance for borrowed funds used during construction (AFC) of approximately $2 million, due to lower construction work in progress balances in 2004 compared to 2003.
For the year ended December 31, 2003, total interest charges increased relative to the same period in 2002 due to an increase of approximately $4 million resulting from amortizations of administrative costs, bond issuance costs and deferred losses generated from the 2003 refinancing. Also contributing to the increase was lower credits from the allowance for borrowed funds used during construction (AFC) of approximately $4 million due to lower construction work in progress balances in 2003.
7 (Continued)
LONG ISLAND POWER AUTHORITY (A Component Unit of The State of New York)
Management's Discussion and Analysis Years ended December 31, 2004 and 2003 Cash, Cash Equivalents, and Investments The Authority's cash, cash equivalents, and investments totaled approximately $413 million, $418 million and
$610 million at December 31, 2004, 2003, and 2002, respectively. The decrease from 2003 to 2004 is primarily the result of higher fuel and purchased power costs. The decrease from 2002 to 2003 is primarily the result of higher payments related to fuel and purchased power costs (most of which was deferred for future recovery) and funding capital expenditures with cash from operations. The Authority has maintained a S250 million balance in its Rate Stabilization Fund.
Capital Assets During 2004 two new generating facilities were constructed on Long Island by separate entities, with a combined capacity of approximately 96MW. Each of these facilities began supplying capacity and energy to LIPA in accordance with the terms of Power Purchase Agreements (PPA's) negotiated in 2003. Under the terms of the first agreement, LIPA receives 100% of the output from the newly constructed generating unit for a term of 13 years. The agreement contains two optional renewal periods of five years each. This lease qualifies for capitalization under Statement of Financial Accounting Standards (SFAS) No. 13, Accounting for Leases, and has been included in both Utility Plant and Capital Lease Obligations. The second agreement provides LIPA with 10MW of the capacity and energy from a separate facility for a period of 30 years. This lease did not qualify for capitalization.
During 2003 the Authority began taking capacity and energy under two 15-year Power Purchase Agreements (PPA's), each for 100% of the output from two newly constructed generating units with a total capacity of approximately 88MW, which were completed prior to the summer of 2003. Each of these PPA's qualified as capital leases under Statement of Financial Accounting Standards (SFAS) No. 13, Accountingfor Leases, and is included in both Utility Plant and Capital Lease Obligations.
Costs incurred under the PPAs, whether capitalized or not, are includible in fuel and purchased power costs in the period incurred, in accordance with the FPPCA.
For additional information on power purchase agreements, see footnote 11 of notes to basic financial statements.
The Authority also continued its program of strategic investment in transmission and distribution upgrades to improve reliability and to enhance capacity needed to meet growing customer demands. For the years ended December 31, 2004, and 2003, capital improvements totaled S208 million and $202 million, respectively. These improvements included the replacement or upgrade of transformer banks and circuit breakers, new substations, enhanced transmission lines and upgraded command and control equipment.
Promissory Notes Receivable The KeySpan Energy Corporation ("KeySpan") note decreased significantly in 2003 as the Authority called for redemption its $270 million Long Island Lighting Company Debentures, 8.2% Series due 2023, and its NYSERDA financing notes, totaling approximately S177 million, with varying maturity dates between 2019 and 2022. Funding for these redemptions, including interest to the date of redemption and call premiums, was provided by KeySpan in accordance with the terms of a promissory note to LIPA.
8 (Continued)
LONG ISLAND POWER AUTHORITY (A Component Unit of The State of New York)
Management's Discussion and Analysis Years ended December 31, 2004 and 2003 Regulatory Assets Regulatory assets decreased approximately $81 million from December 31, 2003 to December 31, 2004. The decrease is the result of (i) the recovery of a portion of the 2003 deferred Excess Fuel Costs totaling approximately S36 million (the remainder to be collected over a 9-year period in accordance with LIPA's tariff),
(ii) the decrease in the deferred unrealized gains or losses on LIPA's fuel hedges totaling approximately
$41 million and (iii) the scheduled recovery of approximately $35 million related to the Shoreham Property Tax Settlement Agreement through a surcharge on billings for electric service to customers residing in Suffolk County (the Shoreham surcharge), which began in June 2003 (as discussed in greater detail in note 3 of notes to basic financial statements); offset by the additional carrying charges on the Shoreham Property Tax Settlement Agreement related credits totaling approximately $31 million.
Regulatory assets increased approximately $265 million from December 31, 2002 to December 31, 2003. The increase is the result of (i) the issuance of Shoreham Property Tax Settlement Agreement related credits totaling approximately $20 million, additional carrying charges related to the balance of the Shoreham Property Tax Settlement Agreement totaling approximately $30 million, offset by the scheduled recovery of approximately
$19 million through the Shoreham surcharge, which began in June 2003 and (ii) 2003 deferred Excess Fuel Costs totaling approximately S365 million, to be recovered over the 10-year period which began January 1, 2004, in accordance with LIPA's tariffs; offset by (iii) the recovery of 2002 deferred Excess Fuel Costs totaling approximately S130 million.
Capitalization The Authority's capitalization, including current maturities of long-term debt, is as follows:
Capitalization (Thousands of dollars)
Balance at December 31 2004 2003 2002 General Revenue Bonds $ 5,966,549 $ 5,900,544 $ 5,646,894 Subordinated Revenue Bonds 962,345 989,645 1,165,518 Commercial Paper Notes 100,000 100,000 100,000 NYSERDA Notes 155,420 155,420 332,425 Debentures - - 270,000
$ 7,184,314 $ 7,145,609 $ 7,514,837 During 2004, the Authority issued S200 million Electric System General Revenue Bonds, Series 2004A. The issuance consists of $33.9 million of Serial bonds and $166.1 million of Term bonds. The Serial bonds have maturities that begin in 2013 and continue each year through 2025. Interest rates on the Serial bonds range from 3.8% to 4.875%. The Term bonds have maturities of S64.9 million in 2029, $12.4 million in 2032, and
$88.8 million in 2034. Interest rates on the Term bonds are 5.0% and 5.1%. The purpose of these bonds was to reimburse LIPA's treasury for capital projects funded previously with cash from operations, and to provide funding for future capital spending.
9 (Continued)
LONG ISLAND POWER AUTHORITY (A Component Unit of The State of New York)
Management's Discussion and Analysis Years ended December 31, 2004 and 2003 In addition, long-term debt decreased as a result of the scheduled maturities of approximately $186 million, partially offset by the accretion of the capital appreciation bonds totaling $25 million.
During 2003, the Authority undertook various borrowings, remarketings and refundings, as follows:
(i) remarketed S27.3 million Electric System Subordinated Revenue Bonds, Series 8C, as fixed rate bonds maturing April 1, 2010; (ii) issued approximately S622 million of uninsured, fixed rate, senior lien bonds (the Series 2003A & B Bonds, to refund certain series of the Electric System General Revenue Bonds Series 1998A, 1998B, and 2000A); (iii) in connection with the expiration of certain letters of credit supporting the Authority's S700 million Electric System Subordinated Revenue Bonds, Series I through 3, the Authority remarketed $525 million of such Bonds as subordinate lien variable rate or auction rate bonds, and refunded the remaining $175 million with fixed rate senior lien bonds; issued approximately $150 million of fixed rate senior lien bonds to fund certain capital expenditures; and (iv) issued approximately $587 million refunding variable rate bonds to call approximately $587 million of its Electric System General Revenue Bonds Series 1998A (2029 maturity, 5.50%). The refunding variable rate bonds were issued in connection with the swaption entered into by the Authority in October 2002, which was exercised on February 3, 2003. The Authority also called for redemption of $270 million Long Island Lighting Company Debentures, 8.2% Series due 2023, and the early redemption of various NYSERDA financing notes, totaling approximately $177 million, with varying maturity dates between 2019 and 2022. Funding for these redemptions, including interest to the date of redemption and call premium, wvas provided by KeySpan in accordance with the terms of a promissory note to LIPA.
For the year ended December 31, 2002, long term debt decreased as a result of the scheduled maturities of approximately $140 million, partially offset by the accretion of the capital appreciation bonds totaling
$29 million.
The Authority's Supplemental Bond Resolution authorizes the issuance of Commercial Paper Notes, Series CP-1 (the CP-1 Notes) up to a maximum amount of $300 million. In May 2003, the Authority replaced the existing CP Credit Facility securing the CP-1 Notes and re-designated its Commercial Paper Notes into Series CP-1, CP-2, and CP-3. The three substitute CP Credit Facilities have an aggregate principal of $200 million and are supported by a Letter of Credit and Reimbursement Agreement dated May 1, 2003, which expires June 15, 2006. Unless and until additional letters of credit are delivered, the aggregate principal amount of the Commercial Paper Notes will be limited to S200 million. As of December 31, 2004 and 2003, the Authority had Notes outstanding totaling S100 million, leaving $100 million undrawn liquidity available.
Investment Ratings The Authority's securities are rated by Standard and Poor's Corporation (S&P), Moody's Investors Service (Moody's), and Fitch Investors Services, LP (Fitch). The ratings as of March 1, 2005, which reflect an upgrade by Moody's in 2005, are below:
Investment Ratings Standard Moody's & Poors Fitch Senior Lien Debt A3 A- A-lo (Continued)
LONG ISLAND POWER AUTHORITY (A Component Unit of The State of New York)
Management's Discussion and Analysis Years ended December 31, 2004 and 2003
- Certain Senior and all Subordinated Lien debt and the Commercial Paper Notes are supported by either a Letter of Credit (LOC) or are insured. Such debt carries the ratings of the LOC syndicate or insurance company, not that of the Authority.
Risk Management The Authority is routinely exposed to commodity and interest rate risk. In order to mitigate such exposure, the Authority formed an Executive Risk Management Committee to strengthen executive management oversight for the risk mitigation activities of the Authority. In addition, the Authority retains an external consultant specializing in risk management, energy markets and energy trading to enhance its understanding of these areas.
Whenever the Authority enters into a transaction to mitigate risk, it becomes exposed to an event of nonperformance by the counterparty. To limit its exposure to such risk, the Authority will only enter into derivative transactions with counterparties that have a credit rating of "investment grade" or better. For commodity derivatives the Authority requires collateral for mark to market values above an established credit limit for each counterparty.
The goal of the Authority's risk management program is to reduce the impact that energy price volatility and interest rate fluctuations could have on rates if not mitigated with derivative products.
Fuel and purchasedpower transactions: - The Authority uses derivative financial instruments to protect its customers from market price fluctuations for the purchase of fuel oil, natural gas, and electricity. These instruments are recorded at their market value. Any unrealized gains and losses are deferred until realized, in accordance with the modifications to the FPPCA. Upon realization, such gains and losses will be reflected in income and considered in the determination of the FPPCA. At December 31, 2004 and 2003, the Authority had unrealized gains (losses) on commodity derivatives of approximately S24 million and (S17) million, respectively.
Interest rate transactions:- During 2004, the Authority entered into a basis swap with three counterparties for a notional amount of approximately $1 billion under terms that require LIPA to pay the counterparties the Bond Market Association (BMA) Index in exchange for a fixed percent of LIBOR. This agreement became effective July 1, 2004, and continues through August 15, 2033. Under the terms of the agreement, LIPA received, on June 28, 2004, an up front premium of $35 million which is being amortized as an interest rate modifier over the life of the agreement.
The Authority also entered into two fixed-to-floating rate swap agreements, each with a notional amount of approximately $101 million. Under the terms of these identical agreements, LIPA pays a floating rate equal to the BMA index, and receives a fixed rate of interest. The agreements became effective July 1, 2004, and are co-terminus with the underlying securities, the last of which matures September 1, 2016. These agreements are cancelable by the counterparties on July 1, 2007.
In 2003, the Authority entered into a floating-to-fixed rate interest swap agreement with a notional amount of SI 16 million, related to the Authority's 2001L General Revenue Bonds. This swap was designed to reverse a fixed-to-floating swap agreement that the Authority had entered into in May 2001. This swap is for the same term as the original swap, has a floating rate based on BMA Index, and has a fixed interest rate not higher than 5.1875%. The Authority received S8.2 million on the date of closing, which is being amortized as an interest rate modifier over the life of the swap.
II (Continued)
LONG ISLAND POWER AUTHORITY (A Component Unit of The State of New York)
Management's Discussion and Analysis Years ended December 31, 2004 and 2003 In February 2003, UBS AG exercised its option to hedge the call feature of the Authority's $587 million Electric System General Revenue Bonds, Series 1998A, 5.50% maturing in 2029. In exchange for the option, the Authority received an upfront option premium of $82 million plus administrative costs totaling approximately
$24.4 million. As a result of the exercise of the option, the Authority issued $587 million Electric System General Revenue Bonds, Series D through 0, variable rate bonds, in order to call its 1998A 5.50% Electric System General Revenue Bonds. In exchange for the upfront premium, the Authority received a floating-to-fixed interest rate swap on its variable rate bonds. The $106 million premium the Authority received is being amortized as an interest rate modifier over the life of the variable rate debt.
In accordance with SFAS No. 133, Accounting for Derivatives and Hedging Activities, as amended by SFAS No. 138, Accounting for Certain Derivative Instruments and Certain Hedging Activities, and SFAS No. 149, Amendment of Statement 133 on DerivativeInstruments andHedging Activities, the Authority marked-to-market its swap transactions at December 31, 2004 and 2003, and recorded unrealized gains and losses. These gains and losses have been deferred, and will be charged to expense when realized.
Other Power Supply During 2004, the Authority entered into several agreements for capacity and energy necessary to continue to satisfy the increasing energy demand of Long Island, while increasing the diversity of its fuel mix alternatives.
These contracts are for: i) 100% of the output from two newly constructed facilities with total combined capacity of approximately 160MW, to be commercially operational by the summer of 2005, and ii) the construction and installation of a submarine cable to connect Long Island to the power supplies of the PJM Interconnection, to be commercially operational by the summer of 2007. In addition, the Authority has entered into negotiations for the construction and operation of a 350MW (LIPA's allocation is approximately 300MW) combined cycle gas fired facility on Long Island, to be commercially operational by the summer of 2009, and for a 140MW off-shore wind farm with a targeted commercial operation date of 2008.
Contacting the Long Island Power Authority This financial report is designed to provide our bondholders, customers, and other interested parties with a general overview of the Authority's finances and to demonstrate its accountability for the money it receives. If you have any questions about this report or need additional information, contact the Authority at 333 Earle Ovington Blvd., Suite 403, Uniondale, New York 11553, or visit our website at www.lipower.org.
12
LONG ISLAND POWER AUTHORITY (A Component Unit of the State of New York)
Balance Sheet December 31, 2004 and 2003 (Dollars in thousands)
Assets 2004 2003 Current assets:
Cash and cash equivalents S 335,068 $ 219,095 Investments 77,900 198,892 Accounts receivable (net of allowance for doubtful accounts of $19,635 and S 19,485, respectively) 274,184 235,732 Other accounts receivable 11,344 24,978 Fuel inventory 66,948 54,651 Material and supplies inventory 7,128 7,130 Interest receivable 300 602 Prepayments and other current assets 9,732 5,836 Total current assets 782,604 746,916 Noncurrent assets:
Utility plant and property and equipment, net 3,540,103 3,390,387 Promissory notes receivable:
KeySpan Energy 155,425 155,425 Total promissory notes receivable 155,425 155,425 Nonutility property and other investments 120,213 72,192 Deferred loss related to nonfuel derivatives 86,177 39,671 Deferred charges 93,972 80,431 Regulatory assets:
Shoreharn property tax settlement 572,101 575,660 Fuel and purchased power costs recoverable 304,256 381,880 Total regulatory assets 876,357 957,540 Acquisition adjustment (net of accumulated amortization of $902,891 and $790,211, respectively) 3,192,620 3,305,300 Total assets $ 8,847,471 $ 8,747,862 I See accompanying notes to basic financial statements.
13
Liabilities and Net Assets 2004 2003 Current liabilities:
Short-term debt $ 100,000 $ 100,000 Current maturities of long-term debt 193,630 186,380 Current portion of capital lease obligation 89,552 80,073 Accounts payable and accrued expenses 275,054 329,971 Accrued payments in lieu of taxes 38,082 38,552 Accrued interest 44,465 42,000 Customer deposits 24,721 25,252 Total current liabilities 765,504 802,228 Noncurrent liabilities:
Long-term debt 6,865,277 6,835,943 Capital lease obligation 772,800 721,630 Asset retirement obligation 68,320 64,452 Deferred credits 85,323 130,196 Deferred credits - financial derivatives 228,126 151,737 Deferred gain - financial derivatives 10,410 8,575 Claims and damages 20,091 21,481 Commitments and contingencies (note 11)
Total noncurrent liabilities 8,050,347 7,934,014 Net assets (deficit):
Invested in capital assets net of related debt (634,292) (566,082)
Unrestricted 665,912 577,702 Total net assets 31,620 11,620 Total liabilities and net assets $ 8,847,471 $ 8,747,862 14
LONG ISLAND POWER AUTHORITY (A Component Unit of the State of New York)
Statement of Revenues, Expenses, and Changes in Net Assets Years ended December 31, 2004 and 2003 (Dollars in thousands) 2004 2003 Operating revenues - electric sales $ 2,853,837 $ 2,583,603 Operating expenses:
Operations - fuel and purchased power 1,386,907 1,076,969 Operations and maintenance 691,937 733,655 General and administrative 40,962 44,875 Depreciation and amortization 229,316 230,085 Payments in lieu of taxes 215,312 213,382 Total operating expenses 2,564,434 2,298,966 Operating income 289,403 284,637 Nonoperating revenues and expenses:
Other income, net:
Investing income 7,362 9,501 Carrying charges on regulatory asset 31,577 30,481 Other 8,309 14,006 Total other income, net 47,248 53,988 Interest charges and (credits):
Interest on long-term debt, net 298,764 295,958 Other interest 20,110 27,576 Allowance for borrowed funds used during construction (2,223) (4,909)
Total interest charges 316,651 318,625 Total nonoperating revenues and expenses (269,403) (264,637)
Change in net assets before cumulative effect of change in accounting principle 20,000 20,000 Cumulative effect of change in accounting principle 2,873 Change in net assets 0 20,000 22,873 Total net assets (deficit), beginning of year 11,620 (11,253)
Total net assets, end of year $ 31,620 $ 11,620 See accompanying notes to basic financial statements.
15
LONG ISLAND POWER AUTHORITY (A Component Unit of the State of New York)
Statement of Cash Flows Years ended December 31, 2004 and 2003 (Dollars in thousands) 2004 2003 Cash flows from operating activities:
Received from customers for the system sales, net of refunds S 2,896,658 S 2,619,232 Other operating revenues received 28,750 36,024 Paid to suppliers and employees:
Operations and maintenance (781,617) (825,695)
Fuel and purchased power (1,398,626) (1,280,133)
Payments in lieu of taxes (304,004) (294,017)
Net cash provided by operating activities 441,161 255,411 Investing activities:
Net sales (purchases) of investment securities 120,992 (80,552)
Earnings received on investments 5,773 8,406 Other 3,371 8,521 Net cash provided by (used in) investing activities 130,136 (63,625)
Cash flows from capital and related financing activities:
Capital and nuclear fuel expenditures (208,431) (201,506)
Insurance proceeds 747 Swaption proceeds 35,000 29,892 Proceeds of promissory note redemption 447,005 Proceeds from the issuance of bonds, net of issuance costs 192,806 1,580,368 Interest paid, net (288,319) (278,901)
Redemption of long-term debt (186,380) (2,042,282)
Net cash used in capital and related financing activities (455,324) (464,677)
Net increase (decrease) in cash and cash equivalents 115,973 (272,891)
Cash and cash equivalents at beginning of period 219,095 491,986 Cash and cash equivalents at end of period S 335,068 S 219,095 Reconciliation to net cash provided by operating activities:
Operating income S 289,403 S 284,637 Adjustments to reconcile excess of operating income to net cash provided by operating activities:
Depreciation and amortization 229,316 230,085 Nuclear fuel burned 4,951 5,830 Shoreham surcharges (credits), net 35,136 (1,081)
Provision for claims and damages 5,019 17,000 Accretion of asset retirement obligation 3,868 3,648 Other, net (41,995) (4,597)
Changes in operating assets and liabilities:
Accounts receivable, net (24,818) (23,526)
Fuel and material and supplies inventory (12,295) (7,665)
Fuel and purchased power costs recovered related to prior periods 36,085 149,040 Excess fuel and purchased power costs deferred - (364,640)
Accounts payable and accrued expenses (83,509) (33,320)
Net cash provided by operating activities S 441,161 S 255,411 See accompanying notes to basic financial statements.
16
LONG ISLAND PONWER AUTHORITY (A Component Unit of The State of New York)
Notes to Basic Financial Statements December 31, 2004 and 2003 (1) Basis of Presentation The Long Island Power Authority (Authority) was established as a corporate municipal instrumentality of the State of New York, constituting a political subdivision of the State, created by Chapter 517 of the Laws of 1986 (the Act). As such, it is a component unit of the State and is included in the State's annual financial statements.
The Authority reporting entity is comprised of itself and its operating subsidiary the Long Island Lighting Company, a wholly owned subsidiary of the Authority doing business as LIPA. LIPA has 1 share of SI par value common stock authorized, issued and outstanding, which is held by the Authority.
As the Authority holds 100% of the common stock of LIPA and substantially controls the operations of LIPA, under Government Accounting Standard Board No. 14, The FinancialReporting Entity, LIPA is considered a blended component unit of the Authority and the assets, liabilities and results of operations are consolidated with the operation of the Authority for financial reporting purposes.
The Authority and its blended component unit, LIPA, are referred to collectively, as the "Company" in the financial statements. All significant transactions between the Authority and LIPA have been eliminated.
(2) Nature of Operations LIPA, as owner of the transmission and distribution system located in the New York State Counties of Nassau and Suffolk (with certain limited exceptions) and a small portion of Queens County known as the Rockaways (Service Area), is responsible for supplying electricity to customers within the service area. To assist LIPA in meeting these responsibilities, LIPA contracted with KeySpan Energy Corporation (KeySpan) or its affiliates to provide: operations and management services related to the transmission and distribution system through a management services agreement (MSA); capacity and energy from the fossil fired generating plants of KeySpan, formerly owned by LILCO, through a power supply agreement (PSA);
and, energy and fuel management services through an energy management agreement (EMA) (collectively; the Operating Agreements). Through these contracts, LIPA pays KeySpan directly for these services and KeySpan, in turn, pays the salaries of its employees and fees of its contractors and suppliers. In 2004, LIPA paid to KeySpan approximately $1.7 billion under the operating agreements, which includes all fees under such agreements, reimbursement for various taxes and PILOTS, certain fuel and purchases power costs, major capital projects, conservation services, research and development and various other expenditures authorized by the Company.
The Authority and LIPA are also parties to an Administrative Services Agreement, which describes the terms and conditions under which the Authority provides personnel, personnel-related services, and other services necessary for LIPA to provide service to its customers. As compensation to the Authority for the services described above, the Authority charges LIPA a monthly management fee equal to the costs incurred by the Authority in order to perform its obligations under the agreements described above.
17 (Continued)
LONG ISLAND POWER AUTHORITY (A Component Unit of The State of New York)
Notes to Basic Financial Statements December 31, 2004 and 2003 (3) Summary of Significant Accounting Policies (a) General The Company complies with all applicable pronouncements of the Governmental Accounting Standards Board (GASB). In accordance with GASB Statement No. 20, Accounting and Financial Reporting for ProprietaryFunds and Other Governmental Entities That Use ProprietaryFund Accounting, the Company complies with all authoritative pronouncements applicable to nongovernmental entities (i.e., pronouncements of the Financial Accounting Standards Board) that do not conflict with GASB pronouncements.
The operations of the Company are presented as an enterprise fund following the accrual basis of accounting in order to recognize the flow of economic resources. Under this basis, revenues are recognized in the period which they are earned and expenses are recognized in the period in which they are incurred.
(b) Accountingfor the Effects ofRate Regulation The Company is subject to the provisions of Statement of Financial Accounting Standards (SFAS)
No. 71, Accounting for the Effects of Certain Types of Regulation (SFAS No. 71). This statement recognizes the economic ability of regulators, through the ratemaking process, to create future economic benefits and obligations affecting rate-regulated companies. Accordingly, the Company records these future economic benefits and obligations as regulatory assets and regulatory liabilities, respectively.
Regulatory assets represent probable future revenues associated with previously incurred costs that are expected to be recovered from customers. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are expected to be refunded to customers through the ratemaking process.
In order for a rate-regulated entity to continue to apply the provisions of SFAS No. 71, it must continue to meet the following three criteria: (1) the enterprise's rates for regulated services provided to its customers must be established by an independent third-party regulator or its own governing board empowered by a statute to establish rates that bind customers; (2) the regulated rates must be designed to recover the specific enterprise's costs of providing the regulated services; and (3) in view of the demand for the regulated services and the level of competition, it is reasonable to assume that rates set at levels that wvill recover the enterprise's costs can be charged to and collected from customers.
Based upon the Company's evaluation of the three criteria discussed above in relation to its operations, and the effect of competition on its ability to recover its costs, the Company believes that SFAS No. 71 continues to apply.
If the Company had been unable to continue to apply the provisions of SFAS No. 71, as of December 31, 2004, the Company estimates that approximately $304.3 million of regulatory assets would be considered for write-off, and the acquisition adjustment, totaling approximately
$3.2 billion would be considered for impairment.
18 (Continued)
LONG ISLAND PONWER AUTHORITY (A Component Unit of The State of New York)
Notes to Basic Financial Statements December 31, 2004 and 2003 (c) Utility PlantandPropertyandEquipment Additions to and replacements of utility plant are capitalized at original cost, which includes material, labor, indirect costs associated with an addition or replacement, plus an allowance for borrowed funds used during construction. The cost of renewals and betterments relating to units of property is added to utility plant. The cost of property replaced, retired or otherwise disposed of is deducted from utility plant and, generally, together with dismantling costs less any salvage, is charged to accumulated depreciation. The cost of repairs and minor renewals is charged to maintenance expense. Mass properties (such as poles, wire and meters) are accounted for on an average unit cost basis by year of installation.
Property and equipment represents leasehold improvements, office equipment and furniture and fixtures of the Authority.
(d) Cash and Cash Equivalents andInvestments Funds held by the Authority are administered in accordance with the Authority's investment guidelines pursuant to Section 2925 of the New York State Public Authorities Law. These guidelines comply with the New York State Comptroller's investment guidelines for public authorities. Certain investments and cash and cash equivalents have been designated by the Authority's Board of Trustees to be used for specific purposes, including rate stabilization, debt service, capital expenditures, the issuance of credits in accordance with the Shoreham Property Tax Settlement Agreement, and Clean Energy initiatives. Investments' carrying value is reported at amortized cost, which approximates fair market value.
(e) Fuel Inventory Under the terms of the EMA and various Power Purchase Agreements, LIPA owns the fuel oil used in the generation of electricity at the facilities under contract to LIPA. Fuel inventory represents the value of low sulfur and internal combustion fuels that LIPA had on hand at each year-end in order to meet the demand requirements of these generating stations. Fuel inventory is valued using the weighted average cost method.
09 Aaterial andSupplies Inventory This represents LIPA's share of material and supplies inventory needed to support the operation of the Nine Mile Point 2 (NMP2) nuclear power station.
(g) PromissoryNote Receivable As part of the 1998 Merger, KeySpan issued promissory notes to LIPA of approximately
$1.048 billion. As of December 31, 2004 and 2003, approximately S155.4 million remained outstanding, respectively. The interest rates and timing of principal and interest payments on the promissory notes from KeySpan are identical to the terms of certain LILCO indebtedness assumed by LIPA in the merger. KeySpan is required to make principal payments to LIPA thirty days prior to the corresponding payment due dates, and LIPA transfers those amounts to the debt holders in accordance with the original debt repayment schedule.
19 (Continued)
LONG ISLAND POWVER AUTHORITY (A Component Unit of The State of New York)
Notes to Basic Financial Statements December 31, 2004 and 2003 (1) DeferredLoss Related to Non-FutelDerivatives The Authority uses financial derivative instruments to manage the impact of interest rates on its customers, earnings and cash flows. Under the provisions of SFAS No. 133, Accounting for Derivatives and Hedging Activities, as amended by SFAS No. 138, Accounting for Certain Derivative Instruments and Certain Hedging Activities, and SFAS No. 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities, the Authority is required to recognize the fair value of all derivative instruments as either an asset or liability on the balance sheet with an offsetting gain or loss recognized in earnings or deferred charges. These standards permit the deferral of hedge gains and losses to Other Comprehensive Income, under specific hedge accounting provisions, until the hedged transaction is realized. However, the Authority is a governmental agency and, therefore, its financial statements are prepared in accordance with the provisions of the Governmental Accounting Standards Board, which do not provide for Other Comprehensive Income.
As the Authority is subject to the provisions of SFAS No. 71, all such gains and losses are deferred until realized. Accordingly, the Authority's balance sheet reflects the inclusion of deferred losses and the deferred gains.
(i) Deferred Charges Deferred charges represent primarily the unamortized balance of costs incurred to issue long-term debt. Such amounts are amortized to interest expense over the life of the debt issuance to which they relate.
6F) RegulatoryAssets Shoreham PropertyTax Settlement ("Settlement')
In January 2000, the Authority reached an agreement with Suffolk County, Town of Brookhaven, Shoreham-Wading River Central School District, Wading River Fire District and Shoreham-Wading River Library District (which was succeeded by the North Shore Library District) (collectively, the Suffolk Taxing Jurisdictions) and Nassau County regarding the over assessment of the Shoreham, Nuclear Power Station. As required under the terms of the agreement, the Authority was required to issue S457.5 million of rebates and credits to customers over the five-year period which began May 29, 1998. In order to fund such rebates and credits, the Authority used the proceeds from the issuance in May 1998 of its Capital Appreciation Bonds, Series 1998A Electric System General Revenue Bonds totaling approximately $146 million and the issuance in May 2000 of approximately
$325 million of Electric System General Revenue Bonds, Series 2000A.
As provided under the Agreement, beginning in June 2003, LIPA's Suffolk County customers' bills include a surcharge (the Suffolk Surcharge) to be collected over the succeeding approximate 25 year period to repay the Authority for debt service and issuance costs on the bonds issued by the Authority to fund the Settlement as well as its cost of pre-funding certain rebates and credits.
20 (Continued)
LONG ISLAND POWER AUTHORITY (A Component Unit of The State of New York)
Notes to Basic Financial Statements December 31, 2004 and 2003 As future rates will be established at a level sufficient to recover all such costs identified above, LIPA recorded a regulatory asset in accordance with SFAS No. 71. The balance of the Shoreham property tax settlement regulatory asset as of December 31, 2004 and 2003 was approximately
$572.1 million and $575.6 million, respectively. The balance represents costs recorded from 1998 through 2004 including rebates and credits issued to customers, costs of administering the program and debt service costs on the Bonds identified above less surcharges collected since May 2003 totaling approximately S54 million.
Fuel andPurchasedPower Costs Recoverable LIPA's tariff includes a fuel recovery mechanism - the Fuel and Purchased Power Cost Adjustment (FPPCA) - whereby customer bills may be adjusted to reflect changes in the cost of fuel, purchased power and related costs. The FPPCA allows LIPA to recover from customers amounts incurred for fuel and purchased power beyond those included in base rates (Excess Fuel Costs).
Modification to the FPPCA Mechanism In February 2003, LIPA's Board of Trustees adopted a proposal to change the method in which the Company collects Excess Fuel Costs from its customers. The modification, fully implemented in 2004, permits the Authority to collect its Excess Fuel Costs in the year incurred (as opposed to on a deferral basis), in amounts sufficient to generate revenues in excess of expenses of S20 million on an annual basis. The modification was implemented over a two-year transition period (2003 - 2004) as follows:
With respect to 2003 excess fuel costs: (i) $75 million was scheduled to be collected in 2003 between March and December; and, (ii) an additional amount sufficient to generate an excess of revenue over expenses of $20 million in 2003 was deferred and is being collected in level annual amounts over a ten year period commencing in January 1, 2004. Approximately S74 million of the $75 million scheduled to be collected in 2003 was billed to customers in 2003. The remaining $1 million was incorporated in the 2004 FPPCA surcharge. With respect to item (ii) above, approximately $365 million was deferred for collection over the ten year period.
- With respect to 2004 and subsequent years' Excess Fuel Costs, collections of these amounts are on a current year basis (with the recovery factor adjusted throughout the year as necessary) in amounts sufficient to generate excess revenue over expenses of $20 million.
Pursuant to the provisions of the revised FPPCA, LIPA's Board of Trustee approved an annual 4.5%
increase in the FPPCA surcharge in February 2004. As a result of continuing increases in fuel and purchased power costs, the Authority increased the surcharge by an additional annual rate of 5.0%
effective June 8, 2004 and by an additional annual rate of 1.0% effective October 1, 2004. The revised surcharge as designed, provided sufficient recovery of Excess Fuel Costs throughout 2004 for LIPA to achieve revenue in excess of expenses of S20 million by year-end.
21 (Continued)
LONG ISLAND POWER AUTHORITY (A Component Unit of The State of New York)
Notes to Basic Financial Statements December 31, 2004 and 2003 To protect its customers from significant market price fluctuations for the purchase of fuel oil, natural gas, and electricity, LIPA uses derivative financial instruments which, are recorded at their market value. Effective with the 2003 modifications to the FPPCA, unrealized gains and losses derived from these derivatives are deferred as a regulatory asset until realized, at which time they are included in current period results as a component of fuel and purchased power.
Accordingly, as of December 31, 2004, the Authority deferred its unrealized gain on fuel derivatives of approximately $24 million.
(k) Acquisition Adjustment The acquisition adjustment represents the difference between the purchase price paid and the net assets acquired from LILCO and is being amortized and recovered through rates on a straight-line basis using a 35-year life.
(7) FairValues of FinancialInstruments The Company's financial instruments approximate their fair market value as of December 31, 2004 and 2003. The fair values of the Company's long-term debt and derivative instruments are based on quoted market prices.
(in) CapitalizedLease Obligations Represents the net present value of various contracts for the capacity and/or energy of certain generation and transmission facilities in accordance with Emerging Issues Task Force No. 01-08, Determining if Whether an Arrangement Containsa Lease, and Statement of Financial Accounting Standards (SFAS) No. 13, Accounting/or Leases. Upon satisfying the capitalization criteria, the net present value of the contract payments is included in both Utility Plant and Capital Lease Obligations.
As of December 31, 2004, and 2003, the unamortized net present value of the minimum lease payments related to the various contracts totaled approximately $862 million, and $801 million, respectively.
As permitted under SFAS No. 71, LIPA recognizes in Fuel and Purchased Power expense an amount equal to the contract payment of the capitalized leases discussed above, as allowed through the ratemaking process. The value of the asset and the obligation are reduced each month so that the balance sheet properly reflects the remaining value of the asset and obligation at each month end.
For a further discussion on the capitalization of capacity and/or energy contracts, please see note 11 of notes to basic financial statements.
22 (Continued)
LONG ISLAND POWER AUTHORITY (A Component Unit of The State of New York)
Notes to Basic Financial Statements December 31, 2004 and 2003 (n) Deferred Credits Deferred credits represent amounts received by the Authority, the final disposition of which remains undetermined. Accordingly, the Authority has deferred the recognition of income until such determination is reached. Certain of these amounts may be returned to customers, the New York Independent System Operation (NYISO), other NYISO market participants, KeySpan or the Internal Revenue Service.
During 2004, amounts determined as due to customers totaling approximately $36 million were applied against the Excess Fuel Costs.
(o) Claims and Damages Losses arising from claims against LIPA, including workers' compensation claims, property damage, and general liability claims are partially self-insured. Storm losses are self-insured by LIPA.
Reserves for these claims and damages are based on, among other things, experience, and expected loss. In certain instances, significant portions of extraordinary storm losses may be recoverable from the Federal Emergency Management Agency.
(p) Revenues Operating revenues are comprised of cycle billings for electric service rendered to customers, based on meter reads, and the accrual of revenues for electric service rendered to customers not billed at month-end. All other revenue not meeting this definition is reported as nonoperating revenue when service is rendered. For the years ended December 31, 2004, and 2003, LIPA received approximately 51% of its revenues from residential sales, 46% from sales to commercial and industrial customers, and the balance from sales to public authorities and municipalities.
(q) Depreciation The provisions for depreciation for utility plant result from the application of straight-line rates by groups of depreciable properties in service. The rates are determined by age-life studies performed on depreciable properties. The average composite depreciation rate is 2.9 1%.
Leasehold improvements are being amortized over the lesser of the life of the assets or the term of the lease, using the straight-line method. Property and equipment is being depreciated over its estimated useful life using the straight-line method.
23 (Continued)
LONG ISLAND POWER AUTHORITY (A Component Unit of The State of New York)
Notes to Basic Financial Statements December 31, 2004 and 2003 The following estimated useful lives and capitalization thresholds are used for utility property:
Capitalization Category Useful life threshold Generation-nuclear 37 - 38 years $ 200 Transmission and distribution 23 - 46 years 200 Common 4 - 42 years 200 Nuclear fuel in process and in reactor 6 years 200 Generation assets under capital lease 15 - 25 years (r) Payments-in-Lieu-of-Taxes The Company is required to make payments-in-lieu-of-taxes (PILOTS) for all operating taxes previously paid by LILCO, including gross income, gross earnings, property, Metropolitan Transportation Authority and certain taxes related to fuels used in utility operations. In addition, the Authority has entered into various PILOT arrangements for property it owns, upon which merchant generation and transmission is built.
(s) Allowancefor Borrowed Funds Used DuringConstruction The allowance for borrowed funds used during construction (AFUDC) is the net cost of borrowed funds used for construction purposes. AFUDC is not an item of current cash income. AFUDC is computed monthly on a portion of construction work in progress, and is shown as a net reduction in interest expense.
(t) Income Taxes The Authority is a political subdivision of the State of New York and, therefore, the Authority and its blended component unit are exempt from Federal, state, and local income taxes.
(u) Asset Retirement Obligation On January 1, 2003, the Authority adopted SFAS No. 143, Accounting for Asset Retirement Obligations. An Asset Retirement Obligation (ARO) exists when there is a legal obligation associated with the retirement of a tangible long-lived asset that results from the acquisition, construction, or development and/or normal operation of the asset. LIPA, as an 18% owner of Nine Mile Point 2 Nuclear Power Station, has a legal obligation associated with its retirement. This obligation is offset by the capitalization of the obligation which is included in "Utility plant and property and equipment, net". As of December 31, 2004 and 2003, respectively, the asset retirement obligation was approximately $68.3 million and $64.5 million.
24 (Continued)
LONG ISLAND PONWER AUTHORITY (A Component Unit of The State of New York)
Notes to Basic Financial Statements December 31, 2004 and 2003 In connection with the adoption of SFAS No. 143 in 2003, net provision for the decommissioning costs related to the nuclear facility of S36.8 million has been reclassified from accumulated depreciation, where it has been recorded previously, to the asset retirement obligation. The Company recorded an additional asset retirement obligation of $26.8 million and increased utility plant, and property and equipment. The required obligation under the standard was approximately S60.8 million as of January 1, 2003, therefore the cumulative effect of the change in accounting principle results in a benefit of approximately $2.8 million.
(v) Long-Lived Assets Long-lived assets, such as property, plant, and equipment, and purchased intangibles subject to amortization, are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is assessed by a comparison of the carrying amount of an asset to estimated undiscounted future cash flows expected to be generated by the asset. If the carrying amount of an asset exceeds its estimated future cash flow, an impairment charge to be recognized is measured by the amount by which the carrying amount of the asset exceeds the fair value of the asset. Assets to be disposed of and assets held for sale are reported at the lower of the carrying amount or fair value less costs to sell, whether reported in continuing operations or in discontinued operations, and are no longer depreciated.
(it) Use of Estimates The accompanying financial statements were prepared in conformity with accounting principles generally accepted in the United States of America which require management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
(x) Reclassifications Certain prior year amounts have been reclassified in the financial statements to conform with the current year presentation.
(4) Risk Management The Authority is routinely exposed to commodity and interest rate risk. In order to mitigate such exposure, the Authority formed an Executive Risk Management Committee.
25 (Continued)
LONG ISLAND PONWER AUTHORITY (A Component Unit of The State of New York)
Notes to Basic Financial Statements December 31, 2004 and 2003 Fuel andpurchasedpower transactions:The Authority uses derivative financial instruments as detailed in the table below. At December 31, 2004, oil related contracts had a fair market value of approximately
$30.7 million, and for natural gas related contracts the fair market value was approximately $24.9 million.
Fuel Derivative Transactions Volume.
Type of contract Duration per month Oil contracts (volumes in barrels):
Options Put Short Jan 05 - Dec 07 75,000-200,000 Call Long Jan 05 - Dec 07 75,000-200,000 Swap Long Jan 05 - Dec 07 420,000-1,007,500 Gas transactions (volumes in decatherms):
Put Short May 05 -Dec 07 140,000-620,000 Call Long May 05 - Dec 08 140,000-620,000 Swap Long Jan 05 - Dec 07 70,000-3,410,000 Basis transactions:
Swap Long Jan 05 - Mar 06 420,000-1,007,500 Interest Rate Transactions: The Authority has entered into several interest rate swap agreements with several counterparties to modify the effective interest rates on outstanding debt as detailed below (thousands of dollars):
December31,2004 Notional Effective Type of Mark to Deferred amount date swap market gain (loss)
S 150,000 11/12/1998 Floating to Fixed $ 11,516 S (11,516) 100,000 11/12/1998 Floating to Fixed 8,630 (8,630) 587,225 6/11/2003 Floating to Fixed (a) 136,133 (36,088) 116,000 4/l/2003 Floating to Fixed (b) 9,194 (1,425) 502,090 7/l/2004 Basis Swap (c) 31,685 (14,618) 251,045 7/1/2004 Basis Swap (d) 15,561 (7,027) 251,045 7/1/2004 Basis Swap (d) 15,407 (6,873)
Total $ 228,126 S (86,177) 116,000 11/1/2001 Fixed to Floating S 8,493 S 8,493 100,995 7/1/2004 Fixed to Floating 1,038 1,038 100,995 7/1/2004 Fixed to Floating 879 879 Total S 10,410 S 10,410 (a) The Authority received an upfront premium totaling approximately $106 million.
(b) The Authority received an upfront premium totaling approximately $8 million.
(c) The Authority received an upfront premium totaling approximately $17.5 million.
(d) The Authority received an upfront premium totaling approximately $8.75 million.
26 (Continued)
LONG ISLAND POWER AUTHORITY (A Component Unit of The State of New York)
Notes to Basic Financial Statements December 31, 2004 and 2003 (5) Rate Matters Under current New York State law, the Authority is empowered to set rates for electric service in the Service Area without the approval of the New York State Public Service Commission (PSC) or any other state regulatory body. However, the Authority has agreed, in connection with the approval of the 1998 merger of the Authority and LILCO (d/b/a LIPA) by the New York State Public Authorities Control Board (the PACB), that it will not impose any permanent increase, nor extend or re-establish any portion of a temporary rate increase, in average customer rates over a 12-month period in excess of 2.5% without approval of the PSC, following a full evidentiary hearing. Another of the PACB conditions requires that the Authority reduce average base rates within LIPA's service area by no less than 14% over a ten year period commencing on the date when LIPA began providing electric service, when measured against LILCO's base rates in effect on July 16, 1997 (excluding the impact of the Shoreham Property Tax Settlement, but adjusted to reflect emergency conditions and extraordinary unforeseeable events).
The LIPA Act requires that any bond resolution of the Authority contain a covenant that it will at all times maintain rates, fees or charges sufficient to pay the costs of operation and maintenance of facilities owned or operated by the Company; PILOTS; renewals, replacements and capital additions; the principal of and interest on any obligations issued pursuant to such resolution as the same become due and payable, and to establish or maintain any reserves or other funds or accounts required or established by or pursuant to the terms of such resolution.
LIPA's tariff includes: (i) the FPPCA, to allow for adjustments to customers' bills to reflect changes in the cost of fuel and purchased power and related costs; (ii) a PILOTS recovery rider, which allows for rate adjustments to accommodate PILOTS; and (iii) a rider providing for the recovery of costs associated with the Shoreham Property Tax Settlement (credits and rebates).
27 (Continued)
LONG ISLAND POWER AUTHORITY (A Component Unit of The State of New York)
Notes to Basic Financial Statements December 31, 2004 and 2003 (6) Utility Plant and Property and Equipment The following schedule summarizes the utility plant and property and equipment of the Authority as of December 31, 2004 (thousands of dollars):
Beginning Ending balance Additions Deletions balance Capital assets, not being depreciated:
Land $ 9,833 $ 108 S - 5 9,941 Retirement work in progress 6,860 16,003 16,013 6,850 Construction in progress 29,806 184,786 141,044 73,548 Total capital assets not being depreciated 46,499 200,897 157,057 90,339 Capital assets, being depreciated:
Generation - nuclear 693,183 7,732 700,915 Transmission and distribution 2,207,033 132,546 13,734 2,325,845 Common 4,440 766 482 4,724 Nuclear fuel in process and in reactor 37,142 9,371 46,513 Office equipment, furniture, and leasehold improvements 2,920 387 3,307 Generation assets under capital lease 844,914 99,484 - 944,398 Total capital assets being depreciated 3,789,632 250,286 14,216 4,025,702 Less accumulated depreciation for:
Generation - nuclear 106,657 26,172 132,829 Transmission and distribution 260,665 89,466 29,728 320,403 Common 653 655 501 807 Nuclear fuel in process and in reactor 32,705 4,951 37,656 Office equipment, furniture, and leasehold improvements 1,853 344 - 2,197 Generation assets under capital lease 43,211 38,835 - 82,046 Total accumulated depreciation 445,744 160,423 30,229 575,938 Net value of capital assets, being depreciated 3,343,888 89,863 (16,013) 3,449,764 Net value of all capital assets $ 3,390,387 $ 290,760 S 141,044 $ 3,540,103 In 2004, depreciation expense related to capital assets was approximately $116.6 million.
28 (Continued)
LONG ISLAND POWER AUTHORITY (A Component Unit of The State of New York)
Notes to Basic Financial Statements December 31, 2004 and 2003 The following schedule summarizes the utility plant and property and equipment of the Authority as of December 31, 2003 (thousands of dollars):
Beginning Ending balance Additions Deletions balance Capital assets, not being depreciated:
Land S 9,057 $ 776 S - S 9,833 Retirement work in progress 15,570 14,794 23,504 6,860 Construction in progress 99,772 189,149 259,115 29,806 Total capital assets not being depreciated 124,399 204,719 282,619 46,499 Capital assets, being depreciated:
Generation - nuclear 666,007 27,176 693,183 Transmission and distribution 1,961,080 258,833 12,880 2,207,033 Common 4,462 22 4,440 Nuclear fuel in process and in reactor 35,848 1,294 37,142 Office equipment, furniture, and leasehold improvements 2,513 407 2,920 Generation assets under capital lease 612,415 232,499 844,914 Total capital assets being depreciated 3,282,325 520,209 12,902 3,789,632 Less accumulated depreciation for:
Generation - nuclear 112,471 25,239 31,053 106,657 Transmission and distribution 211,620 85,421 36,376 260,665 Common 109 566 22 653 Nuclear fuel in process and in reactor 26,875 5,830 32,705 Office equipment, furniture, and leasehold improvements 1,406 447 1,853 Generation assets under capital lease 12,544 30,667 - 43,211 Total accumulated depreciation 365,025 148,170 67,451 445,744 Net value of capital assets, being depreciated 2,917,300 372,039 (54,549) 3,343,888 Net value of all capital assets $ 3,041,699 $ 576,758 $ 228,070 S 3,390,387 In 2003, depreciation expense related to capital assets was approximately $111.7 million.
29 (Continued)
LONG ISLAND POWER AUTHORITY (A Component Unit of The State of New York)
Notes to Basic Financial Statements December 31, 2004 and 2003 (7) Nine Mile Point Nuclear Power Station, Unit 2 (NMP2)
LIPA has an undivided 18% interest in Nine Mile Point 2 Nuclear Power Station (NMP2), located in Scriba, New York, operated by Constellation Nuclear LLC (Constellation).
LIPA's share of the rated capability of NMP2 is approximately 207 megawatts (MW). LIPA's net utility plant investment, excluding nuclear fuel, was approximately $568 million and $587 million as of December 31, 2004 and 2003, respectively. Generation from NMP2 and operating expenses incurred by NMP2 are shared by LIPA at its 18% ownership interest. LIPA is required to provide its share of financing for any capital additions to NMP2. Nuclear fuel costs associated with NMP2 are being amortized on the basis of the quantity of heat produced for the generation of electricity.
LIPA has an operating agreement for NMP2 with Constellation, which provides for a management committee comprised of one representative from each co-tenant. Constellation controls the operating and maintenance decisions of NMP2 in its role as operator. LIPA and Constellation have joint approval rights for the annual business plan, the annual budget and material changes to the budget. In addition to its involvement through the management committee, LIPA employs on-site nuclear oversight personnel to provide additional support to protect LIPA's interests.
Nuclear Plant Decommissioning LIPA is making provisions for decommissioning costs for NMP2 based on a site-specific study performed in 1995, as updated by LIPA's engineering consultants. LIPA's share of the total decommissioning costs for both the contaminated and noncontaminated portions is estimated to be approximately $68.3 million as of December 31, 2004, and is included in the balance sheet as the asset retirement obligation. LIPA maintains a trust fund for its share of the decommissioning costs of NMP2, which as of December 31, 2004 and 2003, had an approximate value of S54.1 million and $48.9 million, respectively. Through continued deposits and investment returns being maintained within these trusts, the Company believes that the value of these trusts in 2046 will be sufficient to meet the Company's decommissioning obligations.
NMP2 Radioactive Waste Constellation has contracted with the U.S. Department of Energy (DOE) for disposal of high-level radioactive waste (spent fuel) from NMP2. Despite a court order reaffirming the DOE's obligation to accept spent nuclear fuel by January 31, 1998, the DOE has forecasted the start of operations of its high-level radioactive waste repository to be no earlier than 2010. LIPA has been advised by Constellation that the NMP2 spent fuel storage pool has a capacity for spent fuel that is adequate until 2012. If additional DOE schedule slippage should occur, the storage for NMP2 spent fuel, either at the plant or some alternative location, may be required. LIPA reimburses Constellation for its 18% share of the cost under the contract at a rate of $1.00 per megawatt hour of net generation, less a factor to account for transmission line losses. Such costs are included in the cost of fuel and purchased power.
Nuclear Plant Insurance Constellation procures public liability and property insurance for NMP2 and LIPA reimburses Constellation for its 18% share of those costs.
30 (Continued)
LONG ISLAND PONWER AUTHORITY (A Component Unit of The State of New York)
Notes to Basic Financial Statements December 31, 2004 and 2003 In November 2002, the Terrorism Risk Insurance Act (TRIA) of 2002 was enacted by the federal government. Under the TRIA, property and casualty insurance companies are required to offer insurance for losses resulting from Certified acts of terrorism. The United States Secretary of State and Attorney General determine certified acts of terrorism. The nuclear property and accidental outage insurance programs, as discussed later in this section provide coverage for Certified acts of terrorism.
Losses resulting from noncertified acts of terrorism are covered as a common occurrence, meaning that if noncertified terrorist acts occur against one or -more commercial nuclear power plants insured by the insurer's of NMP2, within a 12-month period, such acts would be treated as one event and the owners of the currently licensed nuclear power plants in the United States would share one full limit of liability (currently $3.24 billion).
The Price-Anderson Amendments Act mandates that nuclear power generators secure financial protection in the event of a nuclear accident. This protection must consist of two levels. The primary level provides liability insurance coverage of $300 million (the maximum amount available) in the event of a nuclear accident. If claims exceed that amount, a second level of protection is provided through a retrospective assessment of all licensed operating reactors. Currently, this "secondary financial protection" subjects each of the 104 presently licensed nuclear reactors in the United States to a retrospective assessment of up to S100.6 million for each nuclear incident, payable at a rate not to exceed $10 million per year. LIPA's interest in NMP2 could expose it to a maximum potential loss of $18.1 million, per incident, through assessments of up to $1.8 million per year in the event of a serious nuclear accident at NMP2 or another licensed U.S. commercial nuclear reactor.
Constellation participates in the American Nuclear Insurers Master Worker Program that provides coverage for worker tort claims filed for radiation injuries. Effective January 1, 1998, this program was modified to provide coverage to all workers whose nuclear-related employment began on or after the commencement date of reactor operations. Waiving the right to make additional claims under the old policy was a condition for coverage under the new policy. The old and new policies are described below:
Nuclear worker claims reported on or after January 1, 1998 are covered by an insurance policy with an annual industry aggregate limit of $300 million for radiation injury claims against all those insured by this policy.
All nuclear worker claims reported prior to January 1, 1998 are still covered by the old policy.
Insureds under the old policies, with no current operations, are not required to purchase the newer policy described above, and may still make claims against the old policies through 2007. If radiation injury claims under these old policies exceed the policy reserves, all policyholders could be retroactively assessed, with LIPA's share being up to $300,000.
Constellation has also procured $500 million of primary nuclear property insurance and approximately
$2.25 billion of additional protection (including decontamination costs) in excess of the primary layer through the Nuclear Electric Insurance Limited (NEIL). Each member of NEIL, including LIPA, is also subject to retrospective premium adjustments in the event losses exceed accumulated reserves. For its share of NMP2, LIPA could be assessed up to approximately S3.1 million per loss.
31 (Continued)
LONG ISLAND POWER AUTHORITY (A Component Unit of The State of New York)
Notes to Basic Financial Statements December 31, 2004 and 2003 LIPA has obtained insurance coverage from NEIL for the expense incurred in purchasing replacement power during prolonged accidental outages. Under this program, coverage would commence twelve weeks after any accidental outage, with reimbursement from NEIL at the rate of approximately $630,000 per week for the first 52 weeks, reduced to $504,000 per week for an additional 110 weeks for the purchase of replacement power, with a maximum limit of $88.2 million over a three-year period.
NMP2 License Renewal In May 2004, Constellation submitted an application to extend the licensed life of NMP2 by 20 years. If successful, this would extend the license dates to the year 2046. The current review cycle history of the Nuclear Regulatory Commission (NRC) indicates that approval could be expected by the end of 2006.
To maximize its options, LIPA has agreed to fund a pro rata share of the license renewal costs up to the point of approval by the NRC. At the point of approval, LIPA will then have an option to participate in the extended license.
(8) Cash and Cash Equivalents and Investments All investments of the Authority are held by designated custodians in the name of the Authority.
Investments with maturities when purchased of less than 90 days are classified as cash and cash equivalents. The Authority's investments are reported at amortized cost which approximates fair market value.
The bank balances were $8.0 million and $11.9 million as of December 31, 2004 and 2003, respectively.
Cash deposits at banks were collateralized for amounts above the Federal Deposit Insurance Corporation (FDIC) limits with securities held by the custodian banks in the Authority's name. The Authority is required to maintain compensating balances of $1.2 million. All Authority investment securities are classified as securities acquired by a financial institution for the Authority and held by the financial institutions trust department in the Authority's name.
Cash and cash equivalents and investments of the Authority as of December 31, 2004 and 2003 are detailed below (thousands of dollars):
December 31 2004 2003 Cash and cash equivalents and investments:
Commercial paper $ 294,232 $ 161,883 U.S. Government/Agencies 69,994 207,684 Money market mutual funds 16,824 13,244 Master notes 4,316 564 Corporate bonds 20,022 9,998 Time and demand deposits 7,580 24,614 Total cash and cash equivalents and investments $ 412,968 $ 417,987 32 (Continued)
LONG ISLAND POWER AUTHORITY (A Component Unit of The State of New York)
Notes to Basic Financial Statements December 31, 2004 and 2003 (9) Long-Term and Short-Term Debt The Authority financed the cost of the merger and the refinancing of certain of LILCO's outstanding debt by issuing approximately $6.73 billion aggregate principal amount of Electric System General Revenue Bonds and Electric System Subordinated Revenue Bonds (collectively, the Bonds). In conjunction with the issuance of the Bonds, LIPA and the Authority entered into a Financing Agreement, whereby LIPA transferred to the Authority all of its right, title and interest in and to the revenues generated from the operation of the transmission and distribution system, including the right to collect and receive the same. In exchange for the transfer of these rights to the Authority, LIPA received the proceeds of the Bonds evidenced by a Promissory Note.
The Bonds are secured by a Trust Estate as pledged under the Authority's Bond Resolution (the Resolution). The Trust Estate consists principally of the revenues generated by the operation of LIPA's transmission and distribution system and has been pledged by LIPA to the Authority.
33 (Continued)
LONG ISLAND POWER AUTHORITY (A Component Unit of The State of New York)
Notes to Basic Financial Statements December 31, 2004 and 2003 The Company's bond and note indebtedness and other long-term liabilities as of December 31, 2004 are comprised of the following obligations (thousands of dollars):
Beginning Accretion! Retirements! Ending Due within balance additions refundings balance one year Authority debt:
Electric system general revenue bonds:
Series 1998A S 2,219,6365 8,137 S 69,980 $ 2,157,793 S 166,330 Series 1998B 744,205 32,6i25 711,580 Series 2000A 292,123 16,948 - 309,071 Series 2001 A 300,000 - 300,000 Series 2001 B-K 500,000 - 500,000 Series 2001 L-P 316,000 - 316,000 Series 2003A 106,400 19,5;00 86,900 Series 2003B 511,575 36,S975 474,600 Series 2003C 323,380 - 323,380 Series 2003D-O 587,225 - 587,225 Series 2004A 200,000 - 200,000 Subtotal - bonds 5,900,544 225,085 159,C)80 5,966,549 166,330 Electric system subordinate revenue bonds:
Series 1-3 525,000 - 525,000 Series 7 250,000 - 250,000 Series 8 214,645 27,300 187,345 27,300 Subtotal - bonds net 989,645 27,300 962,345 27,300 LIPA Debt:
NYSERDA notes 155,420 155,420 Subtotal - debt 155,420 155,420 Net unamortized discounts/premiums and deferred amortization (23,286) (2,488) (367) (25,407)
Total bonds and notes net of unamortized discounts/
premiums S 7,022,323 $ 222,597 S 186,013 S 7,058,907 S 193,630 Other long-term liabilities:
Deferred credits S 130,196 5 5,105 S 49,978 S 85,323 S Claims and damages 21,481 5,019 6,409 20,091 Capital lease obligation 801,703 99,484 38,835 862,352 89,552 Total other long-term liabilities S . 953,380 S 109,608 S 95,222 S 967,766 S 89,552 Additions to the Series 2000A and Series 1998A bonds represent the current accretion on the capital appreciation bonds.
34 (Continued)
LONG ISLAND POWER AUTHORITY (A Component Unit of The State of New York)
Notes to Basic Financial Statements December 31, 2004 and 2003 The Company's bond and note indebtedness and other long-term liabilities as of December 31, 2003 are comprised of the following obligations (thousands of dollars):
Beginning Accretion/ Retirements/ Ending Due within balance additions refundings balance one year Authority debt:
Electric system general revenue bonds:
Series 1998A S 3,117,288 $ 8,581 S 906,2233 $ 2,219,636 S 69,980 Series 1998B 1,076,020 331,8;15 744,205 32,625 Series 2000A 376,494 17,755 102,1 26 292,123 Series 2001A 300,000 - 300,000 Series 2001B-K 500,000 - 500,000
, I .,, -
Series 2001 L-P .3 I o, Iuu - 316,000 Series 2003A - 106,400 - 106,400 19,500 Series 2003B - 516,075 4,5500 511,575 36,975 Series 2003C - 323,380 - 323,380 Series 2003D-O - 587,225 - 587,225 Subtotal - bonds 5,685,8;02 1,559,416 1,344,6674 5,900,544 159,080 Electric system subordinate revenue bonds:
Series 1-3 700,000 - 175,000 525,000 Series 7 250,000 250,000 Series 8 (subseries A-H) 216.720 25,225 27,300 214,645 27,300 Subtotal - bonds net 1,166.720 25,225 202,300 989,645 27,300 LIPA Debt:
Debentures 270,000 - 270,000 NYSERDA notes 332,425 - 177,005 155,420 Subtotal - debt 602,425 _ 447,005 155,420 Net unamortized discounts/premiums and deferred amortization (14,155) (5,740) 3,391 (23,286)
FMV 1998A Term Bond (25,955) - (25,955) -
Total bonds and notes net of unamortized discounts/
premiums S 7,414,837 S 1,578,901 S 1,971,415 S 7,022.323 S 186,380 Other long-term liabilities:
Deferred credits $ 117,395 5 23,358 S 10,557 S 130,196 S Claims and damages 24,207 17,000 19,726 21,481 Capital lease obligation 599,871 232,499 30,667 801,703 80,073 Total other long-term liabilities S 741,473 S 272,857 S 60,950 S 953,380 S 80,073 Additions to the Series 2000A and Series 1998A bonds represent the current accretion on the capital appreciation bonds.
35 (Continued)
LONG ISLAND POWER AUTHORITY (A Component Unit of The State of New York)
Notes to Basic Financial Statements December 31, 2004 and 2003 The Company's schedule of capitalization for the years ended December 31, 2004 and 2003 is as follows (thousands of dollars):
Interest December 31 Maturity rate Series 2004 2003 Electric system general Revenue bonds:
Serial bonds Annually to 2016 4.250% to 6.000% a 1998 A S 738,310 5 795,320 Term bonds December 1,2018 to 2029 5.000% to 5.750% a 1998 A 1,263,350 1,263,350 Capital appreciation bonds December 1, 2003 to 2028 4.400% to 5.300% a 1998 A 156,133 160,966 Serial bonds Annually to 2016 4.000% to 5.250% a 1998 B 654,435 687,060 Term bonds April 1,2018 4.750% a 1998 B 57,145 57,145 Capital appreciation bonds June 1, 2005 to 2029 5.000% to 5.950% a 2000 A 309,071 292,123 Serial bonds September 1, 2013 to 2021 4.600% to 5.375% a 2001 A 21,960 21,960 Term bonds September 1, 2025 to 2029 5.000% to 5.375% a 2001 A 278,040 278,040 Term bonds May 1, 2033 1.700% b 2001 B 75,000 75,000 Term bonds May 1,2033 1.650% b 2001 C 25,000 25,000 Term bonds May 1,2033 1.700% b 2001 D 50,000 50,000 Term bonds May 1, 2033 1.450% b 2001 E 50,000 50,000 Term bonds May 1, 2033 1.600% b 2001 F 50,000 50,000 Term bonds May 1, 2033 1.550% b 2001 G 50,000 50,000 Term bonds May 1, 2033 1.800% b 2001 H 50,000 50,000 Term bonds May 1, 2033 1.740% b 2001 1 50,000 50,000 Term bonds May 1, 2033 1.560% b 2001 J 50,000 50,000 Term bonds May 1, 2033 1.760% b 2001 K 50,000 50,000 Term bonds May 1, 2033 5.375% a 2001 L 116,000 116,000 Term bonds May 1, 2033 1.450% b 2001 M 50,000 50,000 Term bonds May 1,2033 1.400% b 2001 N 50,000 50,000 Term bonds May 1,2033 1.700% b 2001 0 50,000 50,000 Term bonds May 1,2033 1.500% b 2001 P 50,000 50,000 Serial bonds June 1, 2004 to 2009 3.00% to 5.00% a 2003 A 86,900 106,400 Serial bonds December 1, 2003 to 2014 3.00% to 5.25% a 2003 B 474,600 511,575 Serial bonds September 1, 2013 to 2028 4.25% to 5.50% a 2003 C 137,860 137,860 Term bonds September 1, 2027 to 2033 5.00% to 5.25% a 2003 C 185,520 185,520 December 1,2029 1.09% to 2.00% c 2003 D-H 293,625 293,625 December 1,2029 1.09% to 2.00% b 2003 I-0 293,600 293,600 Serial bonds September 1,2013 to 2025 3.80% to 4.875% a 2004 A 33,900 Term bonds September 1, 2029 to 2034 5.00% to 5.10% a 2004 A 166,100 Electric system subordinated Revenue bonds May 1, 2033 1.98% to 2.20% c Series I A-3A 275,000 275,000 May 1, 2033 1.95% to 2.17% d Series IB-3B 250,000 250,000 April 1,2025 4.210% a Series 7 250,000 250,000 April 1, 2009 to 2012 4.000% to 5.250% a Series 8 187,345 214.645 Total general and subordinated revenue bonds 6,928,894 6,890,189 Commercial paper notes 1.70% to 1.83% b CP-I 100,000 100,000 36 (Continued)
LONG ISLAND POWER AUTHORITY (A Component Unit of The State of New York)
Notes to Basic Financial Statements December 31, 2004 and 2003 Interest December 31 Maturity rate Series 2004 2003 NYSERDA financing notes:
Pollution control revenue bonds March 1, 2016 5.150% a 1985A,B S 108,020 S 108,020 Electric facilities revenue bonds November 1,2023 5.300% a 1993 B 29,600 29,600 October 1,2024 5.300% a 1994A 2,600 2,600 August 1, 2025 5.300% a 1995 A 15,200 15,200 Total NYSERDA financing notes 155,420 155,420 Unamortized premium and deferred amortization (25,4fl7) (23.286)
Total long-term debt 7,158,907 7,122,323 Less current maturities 193,630 186,380 Long-term debt 6,965,277 6,935,943 Net assets 31,620 11,620 Total capitalization S 6.996,897 S 6,947.563 a - Fixed rate b - Variable rate (rate presented is as of December 31, 2004); Auction rate mode reset at rates as determined by auction agent.
c - Variable rate (rate presented is as of December 31, 2004); Weekly interest rate mode reset at rates as determined by remarketing agent.
d - Variable rate (rate presented is as of December 31, 2004); Daily reset rate mode as determined by remarketing agent.
37 (Continued)
LONG ISLAND POWER AUTHORITY (A Component Unit of The State of New York)
Notes to Basic Financial Statements December 31, 2004 and 2003 The debt service requirements for the Company's bonds as of December 31, 2004 are as follows (thousands of dollars):
December 31, 2004 Due Principal Interest Net swap Total 2005 $ 193,630 $ 269,691 $ 19,662 $ 482,983 2006 229,625 260,461 19,662 509,748 2007 241,720 249,384 19,662 510,766 2008 253,155 239,316 19,691 512,162 2009 240,730. 228,175 19,662 488,567 2010-2014 1,014,985 986,096 105,576 2,106,657 2015-2019 1,107,900 776,149 125,119 2,009,168 2020-2024 1,238,975 569,603 114,036 1,922,614 2025-2029 1,551,060 320,338 80,645 1,952,043 2030-2034 1,537,770 94,056 1,631,826 7,609,550 3,993,269 523,715 12,126,534 Unamortized discounts/premiums (25,407) _ _ (25,407)
Unaccreted interest on CABs (525,236) - - (525,236)
Total $ 7,058,907 $ 3,993,269 $ 523,715 $ 11,575,891 Future debt service is calculated using rates in effect at December 31, 2004 for variable rate bonds. The net swap payment amounts were calculated by subtracting the future variable rate interest payments subject to swap agreements from the synthetic fixed rate amount intended to be achieved by the swap agreements.
Electric System General Revenue Bonds Series 2004A The Authority issued Series 2004A Electric System General Revenue Bonds totaling $200 million for various capital projects and to reimburse the Authority for capital expenditures funded with cash from operations. Series 2004A is comprised of Serial Bonds and Term Bonds with maturities beginning September 1, 2013 and continuing through 2034 and pays interest at a fixed rate every March 1 and September 1.
Series 2003A The Authority issued Series 2003A Electric System General Revenue Bonds totaling $106.4 million in order to refund a portion of its Series 2000A Capital Appreciation Bonds. Series 2003A is comprised of Serial Bonds with maturities beginning June 1, 2004 and continuing through 2009 and pays interest at a fixed rate every June 1 and December 1.
38 (Continued)
LONG ISLAND POWER AUTHORITY (A Component Unit of The State of New York)
Notes to Basic Financial Statements December 31, 2004 and 2003 A debt refinancing charge of approximately $9.6 million resulted from these refundings/refinancings. In accordance with the provisions of GASB No. 23, Accounting and FinancialReporting /or Refundings of Debt Reported by ProprietaryActivities (GASB No. 23), the refinancing charge associated with this transaction has been deferred and shown in the balance sheet as deferred amortization within long term debt and is being amortized, on a straight line basis, over the life of the new debt or the old debt, whichever is shorter.
Series 2003B The Authority issued Series 2003B Electric System General Revenue Bonds totaling approximately
$516.1 million in order to refund a portion of its Series 1998A and Series 1998B Bonds. Series 2003B is comprised of Serial Bonds with maturities beginning December 1, 2003, and continuing through 2014 and pays interest at a fixed rate every June I and December 1.
A debt refinancing charge of approximately $25.2 million resulted from these refundings/refinancings. In accordance with the provisions of GASB No. 23, the refinancing charge associated with this transaction has been deferred and shown in the balance sheet as deferred amortization within long term debt and is being amortized, on a straight line basis, over the life of the new debt or the old debt, whichever is shorter.
Series 2003C The Authority issued Series 2003C Electric System General Revenue Bonds totaling approximately
$323.4 million in order to refund a portion of its Series I and Series 2 Bonds totaling $175 million. The remaining proceeds were used to reimburse the Authority's treasury for prior capital expenditures, and to pay the costs associated with the issuance of the bonds. Series 2003C is comprised of Serial and Term Bonds with maturities beginning September 1, 2013 and continuing through 2033 and pays interest at a fixed rate every March 1 and September 1.
Series 2003D through 0 Series 2003 D through 0 Electric System General Revenue Bonds totaling approximately $587.2 million were issued as part of a swaption transaction to refund, the Authority's Electric System General Revenue Bonds Series 1998A maturing on December 1, 2029, 5.50% coupon. Series D through H are comprised of variable rate bonds maturing on December 1, 2029. Interest is calculated in the Weekly Mode and payable on the first business day of each month.
Series 2003 I through 0, are comprised of Auction Rate Term Bonds with a maturity date of December 1, 2029. Each Series bears interest at an auction rate that the Auction Agent advises results from an auction conducted for each applicable auction period.
A debt refinancing charge of approximately $18.1 million resulted from these refundings/refinancings. The refinancing charge associated with this transaction has been deferred and shown in the balance sheet as deferred amortization within long term debt and is being amortized, on a straight line basis, over the life of the new debt or the old debt, whichever is shorter.
39 (Continued)
LONG ISLAND POWER AUTHORITY (A Component Unit of The State of New York)
Notes to Basic Financial Statements December 31, 2004 and 2003 OptionalRedemption Each Series in the Weekly Mode shall be subject to redemption at the option of the Authority on any business day. Each Series of the Auction Rate Bonds are subject to optional redemption prior to maturity, by the Authority, in whole or in part, on any interest payment date immediately following an auction period, at a redemption price equal to the principal amount plus accrued interest to the redemption date; provided, however, that in the event of a partial redemption of Auction Rate Bonds of a Series, the aggregate principal amount of Auction Rate Bonds of such Series which will remain outstanding shall be equal to or more than $10 million unless otherwise consented to by the broker-dealer which acts as the Auction Agent for such Series.
Sinking Fund These Bonds are subject to redemption, in part, beginning on December 1, 2027 through May 1, 2029 from mandatory sinking fund installments.
Electric System Subordinated Revenue Bonds Series I through 3 In connection with the expiration of certain letters of credits, during 2003, the Authority refunded, with Series 2003C, $75 million of its Series 1B and 2A, and $25 million of its Series 2C. As a result of this refinancing transaction the Authority will realize a gross debt service increase of approximately
$ 10 million over the original life of the bonds. The refunding produced an economic loss (the present value of the increase in debt service requirements) of approximately $32 million.
The Bonds that remain outstanding are variable rate bonds payable from and secured by the Trust Estate subject to and subordinated to the Authority's Electric System General Revenue Bonds and are supported by letters of credit that expire on June 15, 2006.
40 (Continued)
LONG ISLAND POWER AUTHORITY (A Component Unit of The State of New York)
Notes to Basic Financial Statements December 31, 2004 and 2003 Series 8 (SubSeries A-H)
This Series is comprised of Current Interest Bonds issued as follows (thousands of dollars):
Mandatory Interest rate This series is comprised purchase date Maturity Principal to mandatory of subseries (April 1) (April 1) outstanding purchase date 8A 2009 $ 23,360 5.25%
8A 2009 2,500 4.13%
8B 2009 17,160 4.30%
8B 2009 10,000 5.25%
8C 2010 25,225 5.00%
8E 2005 2011 27,300 4.50%
8F 2006 2011 27,300 5.00%
8G 2007 2012 27,300 5.00%
8H 2008 2012 27,200 5.00%
$ 187,345 Prior to the mandatory purchase date, the Authority determines to either purchase the Subseries or have such Subseries remarketed. Remarketed securities would become due at the maturity date or an earlier date as determined by the remarketing. The original interest rate on the debt issued will remain in effect until the mandatory purchase date, at which time the interest rate will change in accordance with market conditions at the time of remarketing. Principal, interest, and purchase price on the mandatory purchase date are secured by a financial guaranty insurance policy.
During the years ended December 31, 2004, the Authority redeemed its SubSeries 8D Bonds totaling
$27.3 million. SubSeries 8A through 8C bonds were remarketed and are in the Fixed Rate Mode, and pay interest on April I and October I of each year. The Authority intends to redeem its SubSeries 8E Bonds on the mandatory purchase date of April 1,2005.
Commercial Paper Notes The Authority's Supplemental Bond Resolution authorizes the issuance of Commercial Paper Notes, Series CP-1 through CP-3 (Notes) up to a maximum amount of $200 million. The aggregate principal amount of the Notes outstanding at any time may not exceed $200 million. In connection with the issuance of the Notes, the Authority has entered into a Letter of Credit and Reimbursement Agreement, expiring on June 15, 2006. The Notes do not have maturity dates of longer than 270 days from their date of issuance and as Notes mature, the Authority continually replaces them with additional Notes.
During 2004, the Authority issued an additional $100 million of Commercial Paper Notes to reimburse the Authority's treasury for capital projects. As of December 31, 2004, the Authority redeemed all of this issuance. As of December 31, 2004 and 2003, the Authority had Notes outstanding totaling $ 100 million.
41 (Continued)
LONG ISLAND POWER AUTHORITY (A Component Unit of The State of New York)
Notes to Basic Financial Statements December 31, 2004 and 2003 The Company's short-term indebtedness as of December 31, 2004 and 2003 is comprised of the following obligations (thousands of dollars):
Beginning Ending balance Issuances Retirements balance Short term debt - CP-I $ 100,000 $ - $ - $ 100,000 Short term debt - CP-2 - 50,000 (50,000) -
Short term debt - CP-3 - 50,000 (50,000) -
S 100,000 $ 100,000 $ (100,000) S 100,000 LIPA Debt - Debentures In February 2003, the Authority called for redemption in March, its $270 million Long Island Lighting Company Debentures, 8.2% Series due 2023. Funding for this redemption, including interest to the date of redemption and call premium, totaling approximately $281 million was provided by KeySpan in accordance with the terms of a promissory note with LIPA.
LIPA Debt - NYSERDA Notes In March 2003, the Authority redeemed the following NYSERDA financing notes (thousands of dollars):
Maturity Call Series Principal Rate date premium NYSERDA notes:
EFRBs Series 1989 B $ 35,030 7.15% 9/1/2019 $ 701 EFRBs Series 1990 A 73,900 7.15% 6/1/2020 1,478 EFRBs Series 1991 A 26,560 7.15% 12/1/2020 531 EFRBs Series 1992 B 13,455 7.15% 2/1/2022 269 EFRBs Series 1992 D 28,060 6.90% 8/1/2022 561 Total $ 177,005 $ 3,540 KeySpan also provided funding for this redemption in accordance with the terms of a promissory note with LIPA.
42 (Continued)
LONG ISLAND POWER AUTHORITY (A Component Unit of The State of New York)
Notes to Basic Financial Statements December 31, 2004 and 2003 Fair Values of Long-Tcrm Debt The fair values of the Company's long-term debt as of December 31, 2004 and 2003 were as follows (thousands of dollars):
Fair Value December 31, 2004 2003 Electric System General Revenue Bonds, Series 1998 A $ 2,312,071 $ 2,380,812 Electric System General Revenue Bonds, Series 1998 B 762,682 812,504 Electric System General Revenue Bonds, Series 2000 A 360,780 344,145 Electric System General Revenue Bonds, Series 2001 A 305,863 304,592 Electric System General Revenue Bonds, Series 2001 B through K 500,000 500,000 Electric System General Revenue Bonds, Series 2001 L through P 313,736 316,502 Electric System General Revenue Bonds, Series 2003 A 90,488 112,738 Electric System General Revenue Bonds, Series 2003 B 500,441 546,392 Electric System General Revenue Bonds, Series 2003 C 331,846 330,063 Electric System General Revenue Bonds, Series 2003 D through 0 587,225 587,225 Electric System General Revenue Bonds, Series 2004 A 178,644 Electric System Subordinated Revenue Bonds, Series 1-3 & 1-6 525,000 525,000 Electric System Subordinated Revenue Bonds, Series 7 250,000 250,000 Electric System Subordinated Revenue Bonds, Series 8 (subseries A-H) 199,164 238,673 Electric System Commercial Paper Notes, CP-1 100,000 100,000 NYSERDA Notes 156,440 152,124 Total $ 7,474,380 $ 7,500,770 (10) Retirement Plans The Authority participates in the New York State Employees' Retirement System (the System), which is a cost-sharing, multi-employer, and public employee retirement system. The plan benefits are provided under the provisions of the New York State Retirement and Social Security Law that are guaranteed by the State Constitution and may be amended only by the State Legislature. For full time employees, membership in and annual contributions to the System arc required by the New York State Retirement and Social Security Law. The System offers plans and benefits related to years of service and final average salary, and, effective July 17, 1998; all benefits generally vest after five years of accredited service.
43 (Continued)
LONG ISLAND POWER AUTHORITY (A Component Unit of The State of New York)
Notes to Basic Financial Statements December 31, 2004 and 2003 Members of the System with less than "10 years of service or 10 years of membership" contribute 3% of their gross salaries and the Authority pays the balance of the annual contributions for these employees.
Effective October 1, 2000, members of the System with at least 10 years of service or membership no longer contribute 3% of their gross salaries. The Authority pays the entire amount of the annual contributions of these employees.
Under this plan, the Authority's required contributions and payments made to the System were approximately $867,000, $426,000, and $131,000, for the years ended December31, 2004, 2003, and 2002, respectively. Contributions are made in accordance with funding requirements determined by the actuary of the System using the aggregate cost method.
The State of New York and the various local governmental units and agencies which participate in the Retirement System are jointly represented, and it is not possible to determine the actuarial computed value of benefits for the Authority on a separate basis. The New York State Employees' Retirement System issues a publicly available financial report. The report may be obtained from the New York State and Local Retirement Systems, 110 State Street, Albany, New York 12244.
(11) Commitments and Contingencies (a) PowerSuppl~y Agreement The PSA provides for the sales to LIPA by KeySpan of all of the capacity and, to the extent necessary, energy from the oil and gas-fire generating plants on Long Island formerly owned by LILCO. Such sales of capacity and energy are made at cost-based wholesale rates regulated by the Federal Energy Regulatory Commission (FERC). The rates may be modified in accordance with the terms of the PSA for: i) agreed upon labor and expense indices applied to the base year; ii) a return of and return on net capital additions, which require approval by the Authority; and iii) reasonably incurred expenses that are outside of the control of KeySpan. The PSA rates were reset in 2004, and, in accordance with the agreement, will be reset again in 2009. The annual capacity charge as reset in 2004, was $305.4 million, and the variable charge remained unchanged at $0.90/Mwh. Between 2004 and 2009, the rates will be adjusted annually in accordance with the formula established in the PSA.
The PSA provides incentives and penalties for up to $4 million annually, to maintain the output capability of the facilities, as measured by annual industry-standard tests of operating capability, and to maintain/or make capital improvements which benefit plant availability. The performance incentives averaged approximately $3.9 million in 2004 and 2003.
44 (Continued)
LONG ISLAND POWER AUTHORITY (A Component Unit of The State of New York)
Notes to Basic Financial Statements December 31, 2004 and 2003 (b) PurchasedPower and TransmissionAgreements LIPA has contracts with numerous Independent Power Producers (IPPs) and the New York Power Authority (NYPA) for electric generating capacity. Under the terms of the 2004 amended agreement with NYPA, which will expire in April 2020, LIPA may purchase up to 100% of the electric energy produced at the NYPA facility located within LIPA's service territory at Holtsville, New York. LIPA is required to reimburse NYPA for the minimum debt service payments and to make fixed nonenergy payments associated with operating and maintaining the plant.
With respect to contracts entered into with the IPPs, LIPA is obligated to purchase all the energy they make available to LIPA at prices that often exceed current market prices. However, LIPA has no obligation to the IPPs if they fail to deliver energy.
LIPA also has a contract with NYPA for firm transmission (wheeling) capacity in connection with a transmission cable that was constructed, in part, for the benefit of LIPA. With the inception of the New York Independent System Operator (NYISO) on November 18, 1999, this contract was provided with "grandfathered rights" status. Grandfathered rights allow the contract parties to continue business as they did prior to the implementation of the NYISO. That is, the concept of firm physical transmission service continues. LIPA was provided with the opportunity to convert its grandfathered rights for Existing Transmission Agreements (ETAs) into Transmission Congestion Contracts (TCCs). TCCs provide an alternative to physical transmission reservations, which were required to move energy from point A to point B prior to the NYISO. Under the rules of the NYISO, energy can be moved from point A to point B without a transmission reservation however, the entity moving such energy is required to pay a tolling fee to the owner of the TCC. This tolling fee is called transmission congestion and is set by the NYISO.
Although LIPA has converted its ETA's into TCCs, LIPA will continue to pay all transmission charges per the ETAs, which expire in 2020. In return, LIPA has the right to receive revenues from congestion charges. All such charges and revenue associated with the TCCs are considered components of or reductions to fuel and purchased power costs, and as such are included in the FPPCA calculation.
In addition, in 2000, the Company entered into a lease for a submarine cable running between Connecticut and Long Island whereby LIPA would be entitled to up to 330 megawatts of transmission capacity. The cable was not able to obtain an operating license, as it had been determined that several sections of the cable were not buried to depths required by its permits.
During 2003, the Department of Energy (DOE) issued an emergency order allowing the cable to operate. Because the cable owner has not been able to obtain an operating license, the Authority was under no obligation to remit payments to the owner based on the 2000 lease agreement. As a result, LIPA entered into an interim agreement with the cable owner which established LIPA's ability to pay for 330 megawatts of capacity at a discounted rate from the original lease agreement during the term of the emergency order. In May 2004, the DOE lifted the emergency order.
45 (Continued)
LONG ISLAND PONWER AUTHORITY (A Component Unit of The State of New York)
Notes to Basic Financial Statements December 31, 2004 and 2003 To resolve the outstanding issues associated with the cable, among other things, LIPA entered into a June 24, 2004, Settlement Agreement with certain Connecticut regulators, the cable owner and others. The Settlement Agreement provided for the immediate re-energization and operation of the cable subject to certain conditions, such as the cable meeting the depth requirements under its Connecticut permits. LIPA and the cable owner have negotiated the terms of a Bridge Agreement, which allows LIPA to utilize the cable during the period June 27, 2004 (when the cable was energized pursuant to the Settlement Agreement) to July 1, 2007, which is the new target date for initial commercial operation of the cable. Under the Bridge Agreement, LIPA may purchase 330 MW of firm transmission capacity at a discount from the rate contained in the original lease agreement. LIPA also entered into an amendment to the original agreement with the cable owner extending the original term of the agreement from 20 to 25 years, at the same rate set in the original agreement.
As provided by LIPA's tariff, the costs of all of the facilities noted above will be includable in the calculation of Fuel and Purchased Power Cost. As such, these costs will be recoverable through the FPPCA.
The following table represents LIPA's commitments under purchased power and transmission contracts (thousands of dollars):
Purchased power and transmission contracts Firm Total PPA transmission IPPs* business*
For the years ended:
2005 $ 34,237 S 45,541 $ 118,800 $ 198,578 2006 34,745 45,951 119,600 200,296 2007 35,270 36,801 118,300 190,371 2008 35,813 27,651 120,400 183,864 2009 36,375 27,651 112,100 176,126 2010 through 2014 175,362 138,255 238,400 552,017 2015 through 2019 187,499 138,255 50,300 376,054 2020 through 2024 20,636 82,953 - 103,589 2025 through 2029 - 69,128 - 69,128 2030 through 2034 - 69,128 - 69,128 Total S 559,937 $ 681,314 $ 877,900 $ 2,119,151
- Assumes full performance by NYPA and the IPPs.
46 (Continued)
LONG ISLAND POWER AUTHORITY (A Component Unit of The State of New York)
Notes to Basic Financial Statements December 31, 2004 and 2003 (c) AdditionalPowerSupplies Purchase Power Agreements The Company has contracts with seven private companies to construct and operate 14 generating units at eight sites throughout Long Island. Six of the contracts covering 13 of the units are for 100%
of the capacity, totaling approximately 575 MWs (and energy if needed), for the term of each contract, which vary in duration from three to 25 years. The remaining contract provides the Company with capacity and/or energy of up to I OMW, and is for a term of 30 years.
In accordance with the provisions of SFAS No. 13, Accounting for Leases, six of the contracts, covering 11 of the generating units, have been accounted for as capitalized lease obligations, whereas the remaining leases, covering the other three generating units, will be accounted for as operating leases.
The following table represents LIPA's minimum lease payments under its capacity and/or energy contracts (thousands of dollars):
Purchase Power Agreements Capital Operating Minimum lease/rental payments:
2005 $ 89,552 $ 21,425 2006 88,363 1,796 2007 87,776 1,802 2008 86,198 1,807 2009 85,197 1,813 2010 through 2014 422,538 9,182 2015 through 2019 324,664 9,376 2020 through 2024 81,100 9,595 2025 through 2029 29,827 9,842 2030 through 2035 8,554 Total 1,295,215 75,192 Less imputed interest 432,863 Net present value $ 862,352 $ 75,192 47 (Continued)
LONG ISLAND POWER AUTHORITY (A Component Unit of The State of New York)
Notes to Basic Financial Statements December 31, 2004 and 2003 (d) Office Lease The Authority entered into a noncancelable office lease agreement through January 31, 2011. The future minimum payments under the lease are as follows (thousands of dollars):
Year ended December 31:
2005 $ 1,290 2006 1,338 2007 1,388 2008 1,440 2009 1,494 2010 through 2011 1,680 Total $ 8,630 Rental expense for the office lease amounted to approximately $1.4 million and $1.3 million for the years ended December 31, 2004 and 2003, respectively.
(e) Insurance Programs The Authority's insurance program is comprised of a combination of policies from major insurance companies, self-insurance and contractual transfer of liability, including naming the Authority as an additional insured and indemnification.
The Authority has purchased insurance from the State of New York to provide against claims arising from workers'.compensation. Liability related to construction projects and similar risks is transferred through contractual indemnification and compliance with Authority insurance requirements. The Authority also has various insurance coverages on its interest in Nine Mile Point Nuclear Power Station, Unit 2 as disclosed in detail in footnote 7.
The Authority is self insured for property damage to its transmission and distribution system and up to $3 million for general liability, including automobile liability. The Authority purchased commercially available excess general liability insurance for claims above the $3 million self insurance provision.
48 (Continued)
LONG ISLAND POWER AUTHORITY (A Component Unit of The State of New York)
Notes to Basic Financial Statements December 31, 2004 and 2003 (12) Lcgal Proceedings (a) Environmental In connection with the merger, KeySpan and LIPA entered into Liabilities Undertaking and Indemnification Agreements which, when taken together, provide, generally, that environmental liabilities will be divided between KeySpan and LIPA on the basis of whether they relate to assets transferred to KeySpan or retained by LIPA as part of the merger. In addition, to clarify and supplement these agreements, KeySpan and LIPA also entered into an agreement to allocate between them certain liabilities, including environmental liabilities, arising from events occurring prior to the merger and relating to the business and operations to be conducted by LIPA after the merger (the Retained Business) and to the business and operations to be conducted by KeySpan after the merger (the Transferred Business).
KeySpan is responsible for all liabilities arising from all manufactured gas plant operations (MGP Sites), including those currently or formerly operated by KeySpan or any of its predecessors, whether or not such MGP Sites related to the Transferred Business or the Retained Business. In addition, KeySpan is liable for all environmental liabilities traceable to the Transferred Business and certain scheduled environmental liabilities. Environmental liabilities that arise from the nonnuclear generating business may be recoverable by KeySpan as part of the capacity charge under the PSA.
LIPA is responsible for all environmental liabilities traceable to the Retained Business and certain scheduled environmental liabilities.
Environmental liabilities that existed as of the date of the merger that are untraceable, including untraceable liabilities that arise out of common and/or shared services have been allocated 53.6% to LIPA and 46.4% to KeySpan, as provided for in the merger.
(b) EnvironmentalMatters Retained by LIPA Long Island Sound Transmission Cables. The Connecticut Department of Environmental Protection (DEP) and the New York State Department of Environmental Conservation (DEC) separately have issued Administrative Consent Orders (ACOs) in connection with releases of insulating fluid from an electric transmission cable system located under the Long Island Sound that LIPA owns jointly with the Connecticut Light and Power Company (CL&P). The ACOs require the submission of a series of reports and studies describing cable system condition, operation and repair practices, alternatives for cable improvements or replacement, and environmental impacts associated with prior leaks of fluid into the Long Island Sound. In 2004, in a multi-party Settlement Agreement LIPA and CL&P agreed to remove and replace the existing cables. The Settlement Agreement, and an associated Implementation Plan and Schedule, provide for various penalties if certain project replacement milestones are not met. If this project does not progress as intended, operation of LIPA's Cross Sound Cable may be curtailed. LIPA believes that the milestone will be met at this time, however, there can be no assurance that this will continue. Liability, if any, resulting from this proceeding cannot yet be determined. However, LIPA does not believe that this proceeding will have a material adverse effect on its financial position, cash flows or results of operations.
49 (Continued)
LONG ISLAND POWER AUTHORITY (A Component Unit of The State of New York)
Notes to Basic Financial Statements December 31, 2004 and 2003 In November 2002, a work boat, owned and operated by a third party, dragged its anchor, causing extensive damage to four of the seven cables of the 138-kilovolt facility and the release of a minimal amount of dielectric cable fluid into the Long Island Sound. The work boat had been at the cable site working as part of a large natural gas pipeline project. Temporary repairs were promptly carried out (the cable ends were capped) and permanent repairs completed in June 2003. Litigation arising from the incident commenced in December 2002 and in that litigation LIPA and CL&P aggressively pursued the owner of the work boat as well as the other parties involved in the natural gas pipeline project and who were involved in this incident. As a result of a voluntary mediation in February 2005, LIPA, CL&P and their underwriters reached a settlement agreement with the owner of the work boat and the other parties. It is anticipated that the settlement process should be completed by April 2005.
The same natural gas pipeline project also resulted in another anchor drag incident in February 2003, which damaged the Y49 Cable, a facility owned by NYPA but maintained by LIPA as the primary user. Here, a large barge involved in the project dragged its anchor resulting in the damage to one of the four cables of this facility. Temporary repairs (cable was capped) were completed within ten days and permanent repairs were done by September 2003. Litigation arising from the incident commenced in August 2003. LIPA, as well as NYPA and its property damage insurer are actively engaged in litigation against the barge owner as well as the other parties involved in the incident.
Simazine. Simazine is a commercially available herbicide manufactured by Novartis that was used by LILCO as a defoliant until 1993 under the direction of a New York State Certified Pesticide Applicator. Simazine contamination was found in groundwater at one of the LIPA substations in 1997. LIPA has conducted studies and monitoring activities in connection with this herbicide and is currently working cooperatively with the DEC and others in this matter. Results of these studies, and discussion with the regulatory agencies, have indicated that the environmental impact of this contamination is minimal and remediation work has been completed. However, pending the final conclusion of agency action on this matter, the liability, if any, resulting from the use of this herbicide cannot yet be determined. However, LIPA does not believe that it will have a material adverse effect on its financial position, cash flows, or results of operations.
Superfiind Sites. Under Section 107(a) of the federal Comprehensive Environmental Response, Compensation and Liability Act (CERCLA, also commonly referred to as the Superfund Legislation), parties who generated or arranged for disposal of hazardous substances are liable for costs incurred by the Environmental Protection Agency (EPA) or others who are responding to a release or threat of release of the hazardous substances.
50 (Continued)
LONG ISLAND POWER AUTHORITY (A Component Unit of The State of New York)
Notes to Basic Financial Statements December 31, 2004 and 2003 Metal Bank. In December 1997, the EPA issued its Record of Decision (ROD), in connection with the remediation of a licensed disposal site located in Philadelphia, Pennsylvania, and operated by Metal Bank of America. In the ROD, the EPA estimated that the present worth cost of the selected remedy for the site is $17.3 million. In June 1998, the EPA issued a unilateral administrative order to 13 Potential Responsible Parties (PRPs), including LIPA, for the remedial design and for remedial action at the site. LIPA cannot predict with reasonable certainty the actual cost of the selected remedy, who will implement the remedy, or the cost, if any, to LIPA. Under a PRP participation agreement, LIPA is responsible for 7.95% of the costs associated with implementing the remedy.
LIPA has recorded a liability equal to its estimated cost representing its estimated share of the additional cost to remediate this site. The liability phase of the case was tried in the fall of 2002, which resulted in a finding of liability against Metal Bank in January 2003. At a March, 2003 conference before the federal judge, the court ordered that the second stage trial (determination of the final remedy) be held on November 1, 2003. In May, 2003, the Metal Bank parties filed for Federal Bankruptcy protection under Chapter I1, resulting in a reorganization plan that obligated the emerging entity to fund $13.25 million of the final remedy with no further obligation. In 2003, all the parties (EPA, the PRPs, and two Schorsch brothers [owners who were adjudicated liable early in 2003 along with the Metal Bank parties]) entered into nonbinding mediation of two issues: i) the scope of the remedy, and ii) whether and how much the Schorsch brothers are prepared to contribute.
As a result of that mediation, a final global settlement has been negotiated, which will not require any monetary payment from the PRPs, but will require individual payments from the Schorsch brothers. The terms of a Consent Decree with the PRPs memorializing this settlement is being finalized and is expected to be so ordered by the court in the summer of 2005. Settlement with the Schorsch brothers, whereby they agree to collectively pay $9.6 million total to the EPA and PRPs is still being negotiated and finalized. The damages phase of the case is suspended, pending the outcome of the final settlements. LIPA believes that the global settlement which includes the
$13.25 million from the bankruptcy fund and the $9.6 million from the Schorsch brothers will provide sufficient funding for a full remediation of this site and as such, this proceeding will not have material adverse effect on its financial position, cash flows or results of operations.
PCB Treatment Inc. LILCO has also been named a PRP for disposal sites in Kansas City, Kansas and Kansas City, Missouri. The two sites were used by a company named PCE Treatment, Inc. from 1982 until 1987 for the storage, processing, and treatment of electric equipment, oils, and other materials containing Polychlorinated Biphenyls (PCBs). According to the EPA, the buildings and certain soil areas outside the buildings are contaminated with PCBs. Certain of the PRPs, including LILCO and several other utilities, formed a group, signed a consent order, and investigated environmental conditions at these properties. The work required under this consent order has been completed, and the PRPs, including LIPA, recently signed a second consent order that obligates them to clean up and restore the two contaminated properties. LIPA has been determined to be responsible for less than 1% of the materials that were shipped to this site. Although LIPA is currently unable to determine its precise liability for costs to remediate these sites, LIPA does not believe that this liability will have a material adverse effect on its financial position, cash flows or results of operations.
51l (Continued)
LONG ISLAND POWER AUTHORITY (A Component Unit of The State of New York)
Notes to Basic Financial Statements December 31, 2004 and 2003 Environmental Matters Which May be Recoverable from LIPA by KcySpan Through the PSA A4sharoken. In March 1996, the Village of Asharoken (the Village) filed a lawsuit against LILCO in the New York Supreme Court, Suffolk County (Incorporated Village of Asharoken, New York, et al.
- v. Long Island Lighting Company). Although the Village's negligence claims were dismissed, the causes of action sounding in nuisance remain at issue. Specifically, the Village seeks injunctive relief based upon allegations that the design and construction of the Northport Power Plant upset the littoral drift of sand in the area, thereby causing beach erosion. In a related matter, certain individual residents of the Village commenced an action in New York Supreme Court Suffolk County seeking similar relief (Sbarro v. Long Island Lighting Company). The cases were tried jointly before a judge without a jury. The trial was completed in December 2002 and the parties filed post-trial briefs in March 2003. Since that time, the judge passed away and the case has been reassigned. The parties have agreed that the new judge can decide the case on the existing and supplemental record in lieu of a new trial. Liability, if any, resulting from this proceeding cannot yet be determined. However, LIPA does not believe that this proceeding will have a material adverse effect on its financial position, cash flows or results of operations.
Asbestos Proceedings Litigation is pending in State Court against LIPA, LILCO, KeySpan and various other defendants, involving thousands of plaintiffs seeking damages for personal injuries or wrongful death allegedly caused by exposure to asbestos. The cases for which LIPA may have financial responsibility involve employees of various contractors and subcontractors engaged in the construction or renovation of one or more of LILCO's six major power plants. These cases include' extraordinarily large damage claims, which have historically proven to be excessive. The actual aggregate amount paid to plaintiffs alleging exposure to asbestos at LILCO power plants over the years has not been material to LIPA. Due to the nature of how these cases are litigated, it is difficult to determine how many of the remaining cases that have been filed (or of those that will be filed in the future) involve plaintiffs who were exposed to asbestos at any of the LILCO power plants. Based upon experience, it is likely that LIPA will have financial responsibility in a significantly smaller percentage of cases than are currently pending (or which will be filed in the future) involving plaintiffs who allege exposure to asbestos at any of the LILCO power plants.
52 (Continued)
LONG ISLAND POWER AUTHORITY (A Component Unit of The State of New York)
Notes to Basic Financial Statements December 31, 2004 and 2003 Environmental Matters Which are Currcntly Untraceable for Which LIPA Could Have Responsibility Other Superfund Sites. The Attorney General is in negotiations with LIPA and other parties to achieve settlements at two of three municipal landfills where LILCO allegedly disposed of hazardous substances. The landfills are located in Towns of North Hempstead (the Port Washington Landfill) and Southampton, (the North Sea Landfill). The other municipal landfill where LILCO allegedly disposed of hazardous substances is in the Town of Huntington (the East Northport Landfill). All three landfills have been remediated and the Attorney General is seeking to recover the monies spent by the State in remediating the sites. The East Northport Landfill site was settled with the parties, resulting in an Order on Consent issued by the Attorney General on October 29, 2004. LIPA's share of the settlement was $173,800. The other two sites are still open and the subject of tolling agreements to extend the statute of limitations so that the State does not have to initiate litigation in order to achieve settlements with the various parties. LIPA's share of alleged liability at each site has not been established. LIPA was also served with an Request for Information by the Attorney General seeking information related to LILCO's activities at the Babylon Landfill Site in the Town of Babylon between 1946 and 1992. LIPA has responded to that request even though the statute of limitations has run against the Attorney General for seeking recovery against LIPA. The other potentially responsible parties who have signed tolling agreements could, however, bring an action against LIPA if they are sued by the Attorney General.
Other Matters LIPA may from time to time become a party to various legal proceedings arising in the ordinary course of its business. In the judgment of the Authority and LIPA, these matters will not individually or in the aggregate, have a material effect on the financial position, results of operations or cash flows of LIPA.
Future Environmental Compliance Obligations LIPA, through its contractual obligations to KeySpan under the PSA and the MSA, is subject to the cost of compliance with various current and potential future environmental regulations as promulgated by the federal government and by state and local governments with respect to environmental matters, such as emission of air pollutants, cooling water for generation, the handling and disposal of toxic substances and hazardous, and solid wastes, and the handling and use of chemical products. Electric utility companies generally use or generate a range of potentially hazardous products and by-products that are the focus of such regulation. LIPA is also subject to state laws regarding environmental approval and certification of proposed major transmission facilities.
From time to time environmental laws, regulations and compliance programs may require changes in KeySpan's operations and facilities, which may increase the cost of energy delivery service to LIPA.
Historically, rate recovery has been authorized for environmental compliance costs.
53 (Continued)
LONG ISLAND POWER AUTHORITY (A Component Unit of The State of New York)
Notes to Basic Financial Statements December 31, 2004 and 2003 The Clean Air Act Amendments of 1990 (1990 Amendments) limit emissions of sulfur dioxide (S02) and nitrogen oxides (NOx). The U. S. Environmental Protection Agency (EPA) allocates annual sulfur dioxide emissions allowances to each of the units covered by the PSA ("PSA Units")
based on historical output. NOx are regulated on a regional level through the Ozone Transportation Commission, and are also controlled through allowance allocations. The PSA units are expected to continue to achieve cost effective compliance with these emission control requirements through capital expenditures, the use of natural gas fuel, and the purchase of emission allowances when necessary. LIPA may be required to purchase additional allowances above the PSA unit allocations based on changes in fuel prices. Future requirements of the 1990 Amendments may require further reduction of S02 and NOx emissions, as well as new limits on mercury and nickel emissions.
However, specific control requirements have not been determined by the EPA, and the costs, if any cannot be estimated at this time.
In March 2005, the Federal Clean Air Interstate Rule was promulgated, requiring further reduction of S02 and NOx emissions. Depending on the outcome of one or more legal challenges, compliance requirements would begin in 2010, and are estimated at $4 million rising to as much as $13 million annually in later years. Another rule issued in March 2005, the Hazardous Air Pollutants Rule, set new limits for mercury emissions. While these do not apply to the PSA units, future regulations being considered for nickel would affect PSA units. However, specific control requirements have not been determined by the EPA, and the costs, if any cannot be estimated at this time.
In 2003 the State of New York promulgated separate regulations that would further limit S02 and NOx beginning in 2004. The PSA units are expected to comply with the NOx requirements without additional material expenditures, and utilize lower sulfur fuel to meet the S02 regulations at an approximate cost of $20 million in 2005.
In 2003, the Governor of New York initiated the Regional Greenhouse Gas Initiative to control greenhouse gas emissions in ten Northeastern states. Several similar initiatives are also being considered at the federal level. It is not possible at this time to predict the nature of the requirements that may be imposed, nor their potential operational or financial impacts.
The Clean Water Act (CWA) requires that electric generating stations hold State Pollutant Discharge Elimination System (SPDES) permits, which reflect water quality considerations for the protection of the environment. Additional capital expenditures may be required by the New York State Department of Environmental Conservation (DEC) upon the periodic renewal of these water discharge permits due to recently promulgated changes in Section 316(b) of the CWA. KeySpan is undertaking the study of the impact of current permit conditions on aquatic resources in consultation with the DEC. The nature and extent of any expenditures cannot be determined until these regulations are finalized, and the studies are completed.
54 (Continued)
LONG ISLAND POWER AUTHORITY (A Component Unit of The State of New York)
Notes to Basic Financial Statements December 31, 2004 and 2003 (13) Subsequent Events Generation Purchase Right Agreement (GPRA)
The Authority and KeySpan executed an agreement in June 1997, whereby the Authority secured the right to purchase the interests in the KeySpan subsidiary that owns the on-island generation assets formerly owned by LILCO. Under the terms of the agreement, as amended in March 2002, the Authority bad to exercise such right during the 6-month period that began on November 28, 2003 and ended May 28, 2005.
In March 2005, the Authority and KeySpan entered into another agreement to extend the window for LIPA's option to purchase KeySpan's Long Island generation assets to December 15, 2005.
55
RayM KPMG LLP Suite 200 1305 Walt Whitman Road Melville, NY 11747-4302 Report on Internal Control over Financial Reporting and on Compliance and Other Matters Based on an Audit of Financial Statements Performed in Accordance with Government Auditing Standards The Board of Trustees Long Island Power Authority:
We have audited the basic financial statements of the Long Island Power Authority (Authority) as of and for the year ended December 31, 2004, and have issued our report thereon dated March 21, 2005.
We conducted our audit in accordance with auditing standards generally accepted in the United States of America and the standards applicable to financial audits contained in Government Auditing Standards, issued by the Comptroller General of the United States.
Internal Control Over Financial Reporting In planning and performing our audit, we considered the Authority's internal control over financial reporting in order to determine our auditing procedures for the purpose of expressing our opinion on the basic financial statements and not to provide assurance on the internal control over financial reporting. Our consideration of the internal control over financial reporting would not necessarily disclose all matters in the internal control over financial reporting that might be material weaknesses.
A material weakness is a reportable condition in which the design or operation of one or more of the internal control components does not reduce to a relatively low level the risk that misstatements caused by error or fraud in amounts that would be material in relation to the financial statements being audited may occur and not be detected within a timely period by employees in the normal course of performing their assigned functions. We noted no matters involving the internal control over financial reporting and its operation that we consider to be material weaknesses.
Compliance and Other Matters As part of obtaining reasonable assurance about whether the Authority's basic financial statements are free of material misstatement, we performed tests of its compliance with certain provisions of laws, regulations, contracts and grant agreements, noncompliance with which could have a direct and material effect on the determination of financial statement amounts. However, providing an opinion on compliance with those provisions was not an objective of our audit and, accordingly, we do not express such an opinion. The results of our tests disclosed no instances of noncompliance or other matters that are required to be reported under Government Auditing Standards.
This report is intended solely for the information and use of Authority management, the Authority's Board of Trustees, the New York State Division of the Budget and the New York State Office of the State Comptroller and is not intended to be and should not be used by anyone other than those specified parties.
O>MC, LLUP March 21, 2005 56 KPMG UP,
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UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-K ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended DECEMBER 31, 2004 Commission IRS Employer file number Exact name of registrant 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 (States of incorporation) 750 E. PRATT STREET BALTIMORE, MARYLAND 21202 (Address of principal executive offices) (Zip Code) 410-783-2800 (Registrants' telephone number, including area code)
SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT.
Name of Each Exchange on Tide of each class Which Registered New York Stock Exchange, Inc.
Constellation Energy Group, Inc. Common Stock-Without Par Value J Chicago Stock Exchange, Inc.
I Pacific Exchange, Inc.
6.20% Trust Preferred Securities ($25 liquidation amount per preferred security) issued by BGE Capital Trust II, fully and unconditionally guaranteed, based on several obligations, by Baltimore Gas and Electric Company I
J New York Stock Exchange, Inc.
SECURITIES REGISTERED PURSUANT TO SECTION 12(G) OF THE ACT:
Not Applicable 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 E No O.
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant? knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. E Indicate by check mark whether Constellation Energy Group, Inc. is an accelerated filer E Yes El No Indicate by check mark whether Baltimore Gas and Electric Company is an accelerated filer l Yes 0 No Aggregate market value of Constellation Energy Group, Inc. Common Stock, without par value, held by non-affiliates as of June 30, 2004 was approximately $6,391,974,086 based upon New York Stock Exchange composite transaction dosing price.
CONSTELLATION ENERGY GROUP, INC. COMMON STOCK, WITHOUT PAR VALUE 176,847,227 SHARES OUTSTANDING ON FEBRUARY 28, 2005.
DOCUMENTS INCORPORATED BY REFERENCE Part of Form 10-K Document Incorporated by Reference III Certain sections of the Proxy Statement for Constellation Energy Group, Inc. for the Annual Meeting of Shareholders to be held on May 20, 2005.
Baltimore Gas and Electric Company meets the conditions set forth in General Instruction I(l)(a) and (b) of Form 10-K and is therefore filing this Form in the reduced disclosure format.
TABLE OF CONTENTS Page Forward Looking Statements ........................................................... I PART I Item I - Business. I Overview. ..................................................................... I Merchant Energy Business. 3 Baltimore Gas and Electric Company. 9 Other Nonregulared Businesses .13 Consolidated Capital Requirements .13 Environmental Matters .13 Employees .16 Item 2 - Properties .17 Item 3 - Legal Proceedings .19 Item 4 - Submission of Matters to Vote of Security Holders .19 Executive Officers of the Registrant (Instruction 3 to Item 401(b) of Regulation S-K) .19 PART II Item 5 - Market for Registrant's Common Equity and Related Shareholder Matters .21 Item 6 - Selected Financial Data .22 Item 7 - Management's Discussion and Analysis of Financial Condition and Results of Operations 24 Item 7A - Quantitative and Qualitative Disclosures About Market Risk .58 Item 8 - Financial Statements and Supplementary Data .59 Item 9 - Changes in and Disagreements with Accountants on Accounting and Financial Disclosure .118 Item 9A - Controls and Procedures .118 Item 9B - Other Information .1.................................................................. 8 PART III Item 10 - Directors and Executive Officers of the Registrant ........................................ 118 Item I I - Executive Compensation . ............................................................. 18 Item 12 - Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters ........................................... 119 Item 13 - Certain Relationships and Related Transactions .......................................... 120 Item 14 - Principal Accountant Fees and Services ................................................. 120 PART IV Item 15 - Exhibits and Financial Statement Schedules ............................................. 121 Signatures .................................................................................. 126
Forward Looking Statements
- the effeitiveness of Constellation Energy's and We make statements in this report that are considered BGE's risk management policies and procedures forward looking statements within the meaning of the and the ability and willingness of our Securities Exchange Act of 1934. Sometimes these counterparties to satisfy their financial and statements will contain words such as "believes," performance commitments,
'anticipates," "expects," "intends," 'plans," and other
- operational factors affecting commercial similar words. We also disclose non-historical operations of our generating facilities (including information that represents managements expectations, nuclear facilities) and BGE's transmission and which are based on numerous assumptions. These distribution facilities, including catastrophic statements and projections are not guarantees of our weather-related damages, unscheduled outages future performance and are subject to risks, or repairs, unanticipated changes in fuel costs uncertainties, and other important factors that could or availability, unavailability of coal or gas cause our actual performance or achievements to be transportation or electric transmission services, materially different from those we project. These risks, workforce issues, terrorism, liabilities associated uncertainties, and factors include, but are not limited with catastrophic events, and other events to: beyond our control,
- the timing and extent of changes in commodity
- the actual outcome of uncertainties associated prices and volatilities for energy and energy with assumptions and estimates using judgment related products including coal, natural gas, oil, when applying critical accounting policies and electricity, nuclear fuel, and emission preparing financial statements, including factors allowances, that are estimated in determining the fair value
- the liquidity and competitiveness of wholesale of energy contracts, such as the ability to markets for energy commodities, obtain market prices and, in the absence of
- the effect of weather and general economic and verifiable market prices, the appropriateness of business conditions on energy supply, demand, models and model inputs (including, but not and prices, limited to, estimated contractual load
- the ability to attract and retain customers in obligations, unit availability, forward our competitive supply activities and to commodity prices, interest rates, correlation and adequately forecast their energy usage,
- the timing and extent of deregulation of, and volatility factors),
competition in, the energy markets, and the
- changes in accounting principles or practices, rules and regulations adopted on a transitional
- losses on the sale or write down of assets due basis in those markets, to impairment events or changes in
- regulatory or legislative developments that affect management intent with regard to either deregulation, transmission or distribution rates holding or selling certain assets, and and revenues, demand for energy, or increases
- cost and other effects of legal and in costs, including costs related to nuclear administrative proceedings that may not be power plants, safety, or environmental covered by insurance, including environmental compliance, liabilities.
- the inability of Baltimore Gas and Electric Given these uncertainties, you should not place Company (BGE) to recover all its costs undue reliance on these forward looking statements.
associated with providing electric residential Please see the other sections of this report and our customers service during the electric rate freeze other periodic reports filed with the Securities and period, Exchange Commission (SEC) for more information on
- the conditions of the capital markets, interest these factors. These forward looking statements rates, availability of credit, liquidity, and general represent our estimates and assumptions only as of the economic conditions, as well as Constellation date of this report.
Energy Group's (Constellation Energy) and Changes may occur after that date, and neither BGE's ability to maintain their current credit Constellation Energy nor BGE assume responsibility to ratings, update these forward looking statements.
PART I Constellation Energy was incorporated in Item 1. Business Maryland on September 25, 1995. On April 30, 1999, Overview Constellation Energy became the holding company for BGE and its subsidiaries. References in this report to Constellation Energy is a North American energy company which includes a merchant energy business "we" and "our" are to Constellation Energy and its and BGE, a regulated electric and gas public utility in subsidiaries, collectively. References in this report to the central Maryland. "regulated business(es)" are to BGE.
1
Our merchant energy business is a competitive Constellation Energy maintains a website at provider of energy solutions for a variety of customers. constellation.com where copies of our annual reports on It has electric generation assets located in various Form 10-K, quarterly reports on Form l0-Q, current regions of the United States and provides energy reports on Form 8-K, and any amendments may be solutions to meet customers' needs. Our merchant obtained free of charge. These reports are posted on our energy business focuses on serving the full energy and website the same day they are filed with the SEC. The capacity requirements (load-serving) of, and providing SEC maintains a websitc (sec.gov), where copies of our other energy products and risk management services for filings may be obtained free of charge. The website various customers, such as utilities, municipalities, address for BGE is bge.com. These website addresses are cooperatives, retail aggregators, and commercial and inactive textual references and the contents of these industrial customers. websites are not part of this Form 10-K.
Our merchant energy business includes: In addition, the website for Constellation Energy
- a generation operation that owns, operates, and includes copies of our Corporate Governance Guidelines, Principles of Business Integrity, Corporate maintains fossil, nuclear, and hydroelectric Compliance Program and Insider Trading Policy, and generating facilities and interests in qualifying the charters for the Audit, Compensation and facilities, fuel processing facilities and power Nominating, and Corporate Governance Committees of projects in the United States, the Board of Directors. Copies of each of these
- a marketing and risk management operation documents may be printed from the website or may be that provides energy products and services obtained from Constellation Energy upon written primarily to distribution utilities, power request to the Corporate Secretary.
generators, and other wholesale customers, The Principles of Business Integrity is a code of
- an electric and gas retail operation that provides ethics which applies to all of our directors, officers, and energy services to commercial and industrial employees, including the chief executive officer, chief customers, and financial officer, and chief accounting officer. We will
- an operations and maintenance consulting post any amendments to, or waivers from, the services operation. Principles of Business Integrity applicable to our chief BGE is a regulated electric transmission and executive officer, chief financial officer, or chief distribution utility company and a regulated gas accounting officer on our website.
distribution utility company with a service territory that Operating Segments covers the City of Baltimore and all or part of ten The percentages of revenues, net income, and assets counties in central Maryland. BGE was incorporated in attributable to our operating segments are shown in the Maryland in 1906.
tables below. We present information about our Our other nonregulated businesses: operating segments, including certain special items, in
- design, construct, and operate heating, cooling, Note 3 to ConsolidatedFinancialStatements.
and cogeneration facilities for commercial, Unaffiliated Revenues industrial, and governmental customers Merchant Regulated Regulated Other throughout North America, and Energy Electric Gas Nonregulated
- provide home improvements, service heating, air conditioning, plumbing, electrical, and 2004 75% 16% 6% 3%
indoor air quality systems, and provide natural 2003 67 20 7 6 gas to residential customers in central 2002 35 42 12 11 Maryland. Net Income (1)
In addition, we own several investments that we Merchant Regulated Regulated Other Energy Electric Gas Nonregulated do not consider to be core operations. These include financial investments, real estate projects, and interests 2004 75% 22% 4% (1)%
in a Panamanian distribution facility and in a find that 2003 66 23 9 2 holds interests in two South American energy projects. 2002 47 19 6 28 WVc discuss these non-corc assets in more detail in Total Assets Itrm 7. Management's Discussion and Analysis-Results of Merchant Regulated Regulated Other Operations section. Energy Electric Gas Nonregulated For a discussion of recent events that have 2004 71% 20% 7% 2%
impacted us, please refer to Item 7. Management! 2003 67 23 7 3 Discussion and Analysis-Significant Events section. For a 2002 65 24 7 4 discussion of our strategy, please refer to Item 7. (1) Excludes loss on discontinued operations in 2004 Managements Discussion andAnalysis-Strategy section. and cumulative effects of changes in accounting For a discussion of the seasonaliry of our business, principles in 2003 as discussed in more detail in please refer to Item 7. Managements Discussion and Item 8. FinancialStatements and Supplementary Analysis-Business Environment section. Data.
2
Merchant Energy Business
- Retail Competitive Supply-our operation that Introduction provides electric and gas energy products and Our merchant energy business integrates electric services to commercial and industrial customers.
generation assets with the marketing and risk
- Other-our investments in qualifying facilities management of energy and energy-related commodities, and domestic power projects and our operations allowing us to manage energy price risk over geographic and maintenance consulting services.
regions and time. We present derails about our generating properties Constellation Energy Commodities Group in Item 2. Properties.
(formerly known as Constellation Power Source), our
%wholesalemarketing and risk management operation, Mid-Atlantic Region dispatches the energy from our generating facilities and Wec own 6,418 MW of fossil, nuclear and hydroelectric facilities with which we have power purchase generation capacity in the Mid-Atlantic Region. The agreements, manages the risks associated with selling the output and obtaining non-nudear fuels, and enters into output of these plants is managed by our wholesale transactions to meet customers' energy and risk marketing and risk management operation and is management requirements. Constellation NewEnergy, hedged through a combination of power sales to our electric and gas retail operation, provides electricity, wholesale and retail market participants.
natural gas, transportation, and other energy services to BGE transferred all of these facilities to our commercial and industrial customers. merchant energy generation subsidiaries on July 1, 2000 Constellation Generation Group, our merchant as a result of the implementation of electric customer generation operation, oversees the ownership, choice and competition among suppliers in Maryland, operations, maintenance, and performance of our fossil except for the Handsome Lake project that commenced and nuclear generation and fuel processing facilities. operations in mid-2001. The assets transferred from Our generation capacity supports our wholesale and BGE are subject to the lien of BGE's mortgage.
retail operations by providing a source of reliable power Our merchant energy business provides standard supply that provides a physical hedge for some of our offer service to BGE as discussed in the Baltimorr Gas load-serving activities. and Electric Company-Standard Offer Service section.
Our merchant energy business: Our merchant energy business meets the load-serving
- provided service to distribution utilities, requirements of various contracts using the output from municipalities, and commercial and industrial the Mid-Adantic Region and from purchases in the customers with approximately 31,000 wholesale market. For 2004, the peak load supplied to megawatts (MW) of peak load in the aggregate during 2004, BGE was approximately 4,100 MW.
- provided approximately 279,000 million British Plants with Power Purchase Agreements Thermal Units (mmBTUs) of natural gas to commercial and industrial customers during We own 3,855 MW of nuclear and natural gas/oil 2004, and generation capacity with power purchase agreements for
- managed approximately 12,530 MW of their output. Our facilities with power purchase generation capacity. agreements consist of.
We analyze the results of our merchant energy
- the Nine Mile Point facility, business as follows:
- the Ginna facility, which was acquired in
- Mid-Atlantic Region-our fossil, nuclear, and June 2004, hydroelectric generating facilities and
- the High Desert facility, load-serving activities in the PJM
- the Oleander facility, and Interconnection (PJM) region for which the
- the University Park facility.
output is primarily used to serve BGE. This WeVc own 100% of Nine Mile Point Unit 1 also includes active portfolio management of (609 MW) and 82% of Unit 2 (941 MW). The the generating assets and other physical and remaining interest in Nine Mile Point Unit 2 is owned financial contractual arrangements, as well as by the Long Island Power Authority. Unit I entered other PJM competitive supply activities. service in 1969 and Unit 2 in 1988. Nine Mile Point is
- Plants with Power Purchase Agreements-our located within the New York Independent System generating facilities outside the Mid-Atlantic Operator (NYISO) region.
Region with long-term power purchase We sell 90% of our share of Nine Mile Point's agreements, including our Nine Mile Point output to the former owners of the plant at an average Nuclear Station (Nine Mile Point), RE. Ginna Nuclear Plant (Ginna), Oleander, University price of nearly $35 per megawatt-hour (MWH) under Park, and High Desert generating facilities. agreements that terminate between 2009 and 2011. The
- Wholesale Competitive Supply-our marketing agreements are unit contingent (if the output is not and risk management operation that provides available because the plant is not operating, there is no energy products and services outside the requirement to provide output from other sources). The Mid-Atlantic Region primarily to distribution remaining 10% of Nine Mile Point's output is managed utilities, power generators, and other wholesale by our wholesale marketing and risk management customers. operation and sold into the wholesale market.
3
After termination of the power purchase runs until December 2010, the project will provide agreements, a revenue sharing agreement with the energy exclusively to the CDWR former owners of the plant will begin and continue We have sold portions of the output of the through 2021. Under this agreement, which applies Oleander and University Park facilities ranging from only to Unit 2, a predetermined price is compared to 50% to 100% under tolling contracts for terms ending the market price for electricity. If the market price in 2005 through 2009. Under these tolling contracts, exceeds the strike price, then 80% of this excess amount our respective counterparties will pay a fixed amount is shared with the former owners of the plant. The per month and have the right, but not the obligation, revenue sharing agreement is unit contingent and is to purchase power from us at prices linked to the based on the operation of the unit. variable fuel and other costs of production.
We exclusively operate Unit 2 under an operating agreement with the Long Island Power Authority. The Competitive Supply Long Island Power Authority is responsible for 18% of We are a leading supplier of energy products and the operating costs (and decommissioning costs) of services in North America to wholesale customers and Unit 2 and has representation on the Nine Mile Point retail commercial and industrial customers. We discuss Unit 2 management committee which provides certain our acquisitions of retail commercial and industrial oversight and review functions. operations in Note 15 to the ConsolidatedFinancial In May 2004, we filed an application with the Statements. During 2004, our competitive supply Nuclear Regulatory Commission (NRC) for a 20-year activities served approximately 22,400 MW of peak license extension for both units at Nine Mile Point. load and approximately 279,000 mmBTUs of natural The license on Nine Mile Point's Unit I expires in gas. Our competitive supply activities also include 2,015 2009 and in 2026 on Unit 2. We must demonstrate MW from our Rio Nogales, Holland Energy, Big Sandy, that we can ensure that the units will continue to and Wolf Hills natural gas-fired generating facilities.
perform their intended functions through the renewal These four facilities are not sold forward under period. The NRC will also consider the impact of the long-term agreements, and their output is used to serve 20-year license extension on the environment. We customer requirements.
expect approval of our application by early 2007 and Wholesale and Retail Load-Serving Activities have assumed license extension for purposes of We structure transactions that serve the full energy and recording depreciation expense and asset retirement capacity requirements of various customers outside the obligations. However, we cannot predict the actual PJM region such as distribution utilities, municipalities, timing of the NRC's decision, or the impact of the cooperatives, and retail aggregators that do not own decision, if any, on our financial results. If we do not sufficient generating capacity or in-house supply receive the license extension, we will not be able to functions to meet their own load requirements. We also operate the Nine Mile Point units beyond 2009 and structure transactions to supply full energy and capacity 2026.
requirements and provide natural gas, transportation, In June 2004, we completed our purchase of the and other energy products and services to retail Ginna nuclear facility which is located in Ontario, New commercial and industrial customers.
York from Rochester Gas & Electric Corporation These activities typically occur in regional markets (RG&E). Ginna consists of a 495 megawatt reactor that in which end user customers' electricity rates have been entered service in 1970 and is licensed to operate until deregulated and thereby separated from the cost of 2029. The acquisition includes a long-term unit generation supply. These markets include:
contingent power purchase agreement under which we
- the Northeast (New England and New York),
sell 90% of the plant's output and capacity to RG&E
- the Midwest region, for 10 years at an average price of $44.00 per MWH.
- the West region (Texas and California), and The remaining 10% of the plant's output is managed
- certain areas of Canada.
by our wholesale marketing and risk management Contracts with these customers generally extend operation and sold into the wholesale market.
from one to ten years, but some can be longer. To meet The High Desert facility has a long-term power our customers' load-serving requirements, our merchant sales agreement with the California Department of energy business obtains energy from various sources, Water Resources (CDWR). The contract is a "tolling" including:
structure, under which the CDWR pays a fixed amount
- bilateral power purchase agreements with third of $12.1 million per month which provides CDWR the parties, right, but nor the obligation, to purchase power from
- our generation assets, the project at a price linked to the variable cost of
- regional power pools, and production. During the term of the contract, which 4
- tolling contracts with generation companies, management operation provides products and services to which provide us the right, but not the upstream (exploration and production) and downstream obligation, to purchase power at a price linked (transportation and storage) natural gas customers. We to the variable cost of production, including also include in our other competitive supply activities fuel, with terms that generally extend from the results from our synthetic fuel processing facility in several months to several years but can be South Carolina.
longer.
Other Portfolio Management -We hold up to a 50% voting interest in 24 operating Our wholesale marketing and risk management energy projects that consist of electric generation operation actively uses energy and energy-related (primarily relying on alternative fuel sources), fuel commodities in order to manage our portfolio of energy processing, or fuel handling facilities and are either purchases and sales to customers through structured qualifving facilities under the Public Utility Regulatory transactions. As part of our risk management activities Policies Act of 1978 or otherwise exempt from, or not we trade energy and energy-related commodities to subject to, the Public Utility Holding Company Act of enable price discovery and facilitate the hedging of our 1935. Each electric generating plant sells its output to a load-serving and other risk management products and local utility under long-term contracts.
services. Within our trading function we allow limited We also provide operation and maintenance risk-taking activities for profit. These activities are services, including testing and start-up to owners of actively managed through daily value at risk and electric generating facilities.
liquidity position limits. We discuss value at risk in more detail in Item 7. Managements Discussion and Fuel Sources Analysis-Market Risk. Our power plants use diverse fuel sources. Our fuel mix These activities involve the use of a variety of based on capacity owned at December 31, 2004 and instruments, including: our generation based on actual output by fuel type in
- forward contracts (which commit us to 2004 were as follows:
purchase or sell energy commodities in the future), Fuel Capacity Owned Genera atiofl
- swap agreements (which require payments to or Nuclear .............. 30% 5 2%
from counrerparties based upon the difference Coal .............. 22 3:2 between two prices for a predetermined Natural Gas ........... 30 11D contractual (notional) quantity), Oil .............. 6
- option contracts (which convey the right to buy Renewable and or sell a commodity, financial instrument, or Alternative (1) ...... 3 4 index at a predetermined price), and Dual (2) .............. 9
- futures contracts (which are exchange traded (1) Includes solar, geothermal, hydro, and biomass.
standardized commitments to purchase or sell a (2) Switches between natural gas and oil.
commodity or financial instrument, or make a cash settlement, at a specified price and future We discuss our risks associated with fuel in more date). derail in Item 7. Managemrnts Discusion and Analysis-Active portfolio management allows our wholesale Market Risk.
marketing and risk management operation the ability to: Nuclear
- manage and hedge its fixed-price purchase and The output at our nuclear facilities over the past five sale commitments, years (induding periods prior to our acquisition of Nine
- provide fixed-price commitments to customers Mile Point and Ginna) is presented in the following and suppliers, table:
- reduce exposure to the volatility of cash market Calvert Cliffs Nine Mile Point Ginna prices, and Capacity Capacity Capacity
- hedge fuel requirements at our non-nuclear MWPI Factor aWl Factor MWH Factor generation facilities.
(MWH in millions)
Other Competitive Sitpply Activities 2004 14.5 96% 12.1 89% 4.3 100%
Our wholesale marketing and risk management 2003 13.7 93 12.2 90 3.9 90 operation participates in global coal sourcing activities 2002.. 12.1 82 11.7 87 3.8 89 by providing coal for the variable or fixed supply needs 2001 13.6 92 11.6 86 4.3 100 of North American and international power generators. 2000 .. 13.8 83 11.2 83 3.8 88 In addition, our wholesale marketing and risk .represents our proportionate ownership interest 5
The supply of fuel for nuclear generating stations and sold to pay for the cost of long-term nuclear fuel includes the: storage and disposal. We continue to pay those fees into
- purchase of uranium (concentrates and uranium the DOEs Nuclear Waste Fund for Calvert Cliffs, hexafluoride), Ginna, and Nine Mile Point. The NWPA and our
- conversion of uranium concentrates to uranium contracts with the DOE required the DOE to begin hexafluoride, taking possession of spent nuclear fuel generated by
- enrichment of uranium hexafluoride, and nuclear generating units no later than January 31, 1998.
- fabrication of nuclear fuel assemblies. The DOE has stated that it will not meet that obligation until 2010 at the earliest. This delay has Uranium: We have commitments for sufficient required that we undertake additional actions to provide quantities of uranium (concentrates and on-site fuel storage at Calvert Cliffs, Ginna, and Nine uranium hexafluoride) to meet 100% of Mile Point, including the installation of on-site dry fuel our total requirements through 2006, storage capacity at Calvert Cliffs, as described in more 63% in 2007, and 35% in 2008. We detail below. In 2004, complaints were filed against the experienced price increases in 2004 due federal government in the United States Court of to the federally designated Russian export agent terminating its contract with one of Federal Claims seeking to recover damages caused by our key uranium suppliers. These the DOE's failure to meet its contractual obligation to increases are not expected to continue begin disposing of spent nuclear fuel by January 31, into 2005. 1998. These cases are currently stayed, pending litigation in other related cases.
Conversion: We have commitments providing for the In connection with our purchase of Ginna, all of conversion of all of our uranium RG&E's rights and obligations related to recovery of concentrates into uranium hexafluoride damages from the DOE were assigned to us. However, for our nudear facilities through 2006 we have an obligation to reimburse RG&E for up to and 63% in 2007 and 35% in 2008.
the first $10 million of any recovered damages. We and Enrichment: We have commitments that provide RG&E are currently requesting to allow us to replace 100% of our uranium enrichment RG&E as the party in interest in the complaint filed requirements through 2010 and 25% of against the federal government by RG&E.
these requirements in 2011 and 2012.
Fuel Assembly Storage of Spent Nuclear Fuel-On-Site Facilities Fabrication: We have commitments for the fabrication Calvert Cliffs has a license from the NRC to operate an of fuel assemblies for reloads required on-site independent spent fuel storage installation that through 2008 for Nine Mile Point, expires in 2012. We have storage capacity at Calvert through 2013 at Calvert Cliffs, and Cliffs that will accommodate spent fuel from operations through 2017 for Ginna. through 2008. In addition, we can expand our The nuclear fuel markets are competitive, and temporary storage capacity at Calvert Cliffs to meet although prices for uranium and conversion are future requirements until approximately 2025.
increasing, we do not anticipate any significant Currently, Nine Mile Point and Ginna do not have problems in meeting our future requirements. independent spent fuel storage capacity. Rather, Nine Mile Point's Unit I and Ginna have sufficient storage Storage of Spent Nuclear fuel-FederalFacilities capacity within the plants until 2010. Nine Mile Point's One of the issues associated with the operation and Unit 2 has sufficient storage capacity within the plant decommissioning of nuclear generating facilities is until .2012. After that time, independent spent fuel disposal of spent nuclear fuel. There are no facilities for storage capability may need to be developed at each the reprocessing or permanent disposal of spent nuclear site.
fuel currently in operation in the United States, and the NRC has nor licensed any such facilities. The Nuclear Cost for Decommissioning Uranium Enrichment Facilities Waste Policy Act of 1982 (NWPA) required the federal The Energy Policy Act of 1992 contains provisions government through the Department of Energy (DOE), requiring domestic nuclear utilities to contribute to a to develop a repository for the disposal of spent nuclear fund for decommissioning and decontaminating fuel and high-level radioactive waste. uranium enrichment facilities that had been operated by As required by the NWPA, we are a party to DOE. These contributions are generally payable over a contracts with the DOE to provide for disposal of spent 15-year period with escalation for inflation and are nuclear fuel from our nuclear generating plants. The based upon the amount of uranium enriched by DOE NWPA and our contracts with the DOE require for each utility through 1992. The 1992 Act provides payments to the DOE of one tenth of one cent (one that these costs are recoverable through utility service mill) per kilowatt hour on nuclear electricity generated rates. BGE is solely responsible for these costs as they 6
relate to Calvert Cliffs. The sellers of the Nine Mile renew supply contracts as they expire or enter into Point plant and the Long Island Power Authority are contracts with other coal suppliers. Our primary coal responsible for the costs relating to the Nine Mile Point burning facilities have the following requirements:
plant. The seller of Ginna is responsible for the costs Approximate related to that facility Annual Coal Requirement Special Coal Coit for Decommissioning (tons) Restrictions We are obligated to decommission our nuclear plants at Brandon Shores Sulfur content less the time these plants cease operation. Every two years, Units I and 2 than 1.20 lbs per the NRC requires us to demonstrate reasonable (combined) ... 3,500,000 mmBTU assurance that funds will be available to decommission C. P. Crane the sites. When BGE transferred all of its nuclear Units I and 2 Low ash melting generating assets to our merchant energy business, it (combined) ... 850,000 temperature also transferred the trust fund established to pay for H. A. Wagner decommissioning Calvert Cliffs. At December 31, 2004, Units 2 and 3 Sulfur content no more the trust fund assets were $331.9 million. (combined) ... 1,100,000 than 1%
Under the Maryland Public Service Commission's Coal deliveries to these facilities are made by rail (Maryland PSC) order regarding the deregulation of and barge. The primary source of coal we use is electric generation, BGE ratepayers must pay a total of produced from mines located in central and northern
$520 million, in 1993 dollars adjusted for inflation, to Appalachia. The timely delivery of coal together with decommission Calvert Cliffs through fixed annual the maintenance of appropriate levels of inventory is collections of approximately $18.7 million until necessary to allow for continued, reliable generation June 30, 2006, and thereafter in an annual amount from these facilities.
determined by reference to specified factors. BGE is During 2003, we expanded our coal sources collecting this amount on behalf of Calvert Cliffs. Any including restructuring our rail contracts, increasing the costs to decommission Calvert Cliffs in excess of this range of coals we can consume, adding synthetic fuel as
$520 million must be paid by Calvert Cliffs. If BGE an alternate source, and finding potential other coal rarepayers have paid more than this amount at the rime supply sources including shipments from Columbia, of decommissioning, Calvert Cliffs must refund the Venezuela, South Africa, and other international sources.
excess. If the cost to decommission Calvert Cliffs is less All of the Conemaugh and Keystone plants' annual than the amount BGE's ratepayers are obligated to pay, coal requirements are purchased by the plant operators Calvert Cliffs may keep the difference. from regional suppliers on the open market. The sulfur The sellers of Nine Mile Point transferred a restrictions on coal are approximately 2.3% for the
$441.7 million decommissioning trust fund to us at the Keystone plant and approximately 5.3% for the time of sale. In return, we assumed all liability for the Conemaugh plant.
costs to decommission Unit I and 82% of the costs to The annual coal requirements for the ACE, decommission Unit 2. We believe that this amount is Jasmin, and Poso plants, which are located in adequate to cover our responsibility for California, are supplied under contracts with mining decommissioning Nine Mile Point to a greenfield status operators. The Jasmin and Poso plants are restricted to (restoration of the site so that it substantially matches coal with sulfur content less than 4.0% and ACE is the natural stare of the surrounding properties and the restricted to less than 2.0%.
site's intended use). At December 31, 2004, the Nine All of our requirements reflect historical levels. The Mile Point trust fund assets were $492.2 million. actual fuel quantities required can vary substantially Upon the dosing of the Ginna acquisition, the from historical levels depending upon the relationship seller transferred $200.8 million in decommissioning betveen energy prices and fuel costs, weather funds to us. In return, we assumed all liability for the conditions, and operating requirements.
costs to decommission the unit. WVe believe that this transfer will be sufficient to cover our responsibility for Gas decommissioning Ginna to a greenfield status. At We purchase natural gas, storage capacity, and December 31, 2004, the Ginna trust fund assets were transportation, as necessary, for electric generation at
$209.6 million. certain plants. Some of our gas-fired units can use residual fuel oil or distillates instead of gas. Gas is Coal purchased under contracts with suppliers on the spot We purchase the majority of our coal for electric marker and forward markets, including financial generation under supply contracts with mining exchanges and bilateral agreements. The actual fuel operators, and we acquire the remainder in the spot or quantities required can vary substantially from year to forward coal markets. We believe that we will be able to year depending upon the relationship between energy 7
prices and fuel costs, weather conditions, and operating With respect to power generation, we compete in requirements. However, we believe that we will be able the operation of energy-producing projects, and our to obtain adequate quantities of gas to meet our competitors in this business are both domestic and requirements. international organizations, including various utilities, industrial companies and independent power producers oil (including affiliates of utilities), some of which have Under normal burn practices, our requirements for financial resources that are greater than ours.
residual fuel oil (No. 6) amount to approximately Difficulties in making competitive assessments of 1.5 million to 2.0 million barrels of low-sulfur oil per our company arise from states considering different year. Deliveries of residual fuel oil are made from the types of regulatory initiatives concerning competition in suppliers' Baltimore Harbor marine terminal for the power industry. Increased competition that resulted distribution to the various generating plant locations.
from some of these initiatives in several states Also, based on normal burn practices, we require contributed in some instances to a reduction in approximately 5.0 million to 6.0 million gallons of electricity prices and put pressure on electric utilities to distillates (No. 2 oil and kerosene) annually, but these lower their costs, including the cost of purchased requirements can vary substantially from year to year electricity. While many states continue their support for depending upon the relationship between energy prices retail competition and industry restructuring, other and fuel costs, weather conditions, and operating states that were considering deregulation have slowed requirements. Distillares are purchased from the their plans or postponed consideration of deregulation.
suppliers' Baltimore truck terminals for distribution to In addition, other states are reconsidering deregulation.
the various generating plant locations. We have We believe there is adequate growth potential in contracts with various suppliers to purchase oil at spot the current deregulated market and that further market prices, and for future delivery, to meet our changes could provide additional opportunities for our requirements.
merchant energy business. Our wholesale marketing and risk management operation also participates in global Competition coal sourcing activities by providing coal for the variable Market developments over the past several years have or fixed supply needs of North American and changed the nature of competition in the merchant international power generators. In addition, our energy business. Certain companies within the merchant wholesale marketing and risk management operation energy sector have curtailed their activities or withdrawn provides products and services to upstream and completely from the business. However, new downstream natural gas customers.
competitors (e.g., financial investors) are entering the As the economy continues to recover and the market. We encounter competition from companies of market for commercial and industrial supply continues various sizes, having varying levels of experience, to grow, we have experienced increased competition in financial and human resources, and differing strategies.
our retail commercial and industrial supply activities.
We face competition in the market for energy, The increase in retail competition and the impact of capacity, and ancillary services. In our merchant energy wholesale power prices compared to the rates charged business, we compete with international, national, and by local utilities may affect the margins that we will regional full service energy providers, merchants, and realize from our customers. However, we believe that producers to obtain competitively priced supplies from a our experience and expertise in assessing and managing variety of sources and locations, and to utilize efficient risk will help us to remain competitive during volatile transmission or transportation. We principally compete or otherwise adverse marker circumstances.
on the basis of price, customer service, reliability, and availability of our products.
8
Merchant Energy Operating Statistics 2004 2003 2002 2001 2000 Revenues (In millions)
Mid-Atlantic Fleet $ 1,925.6 $1,696.2 $1,415.1 $1,379.2 S 731.7 Plants with Power Purchase Agreements 756.9 620.0 456.4 70.8 -
Competitive Supply-Retail 4,280.0 2,567.7 312.7 - -
Competitive Supply-Wholesale 3,353.8 2,703.9 540.7 233.5 149.6 Other 73.6 45.1 56.4 80.5 142.5 Total Revenues $10,389.9 $7,632.9 $2,781.3 $1,764.0 $1,023.8 Generation (In millions)-MWH 55.3 51.6 44.7 37.4 18.8 Operating statistics do not relect the elimination of intercompany transactions.
Certain prior-yearamounts have been reclassifiedto conform with the currentyear! presentation.
Baltimore Gas and Electric Company
- Commercial and industrial customers have BGE is an electric transmission and distribution utility several service options that fix competitive company and a gas distribution utility company with a transition charges (CTC) through June 30, service territory that covers the City of Baltimore and 2006. CTC revenues were provided to allow all or part of ten counties in central Maryland. BGE is BGE to recover stranded costs that resulted regulated by the Maryland PSC and Federal Energy from the deregulation of BGE's generating Regulatory Commission (FERC) with respect to rates assets.
and other aspects of its business.
- BGE residential base rates for delivery service BGE's electric service territory incdudes an area of will not change before July 2006. While total approximately 2,300 square miles. There are no residential base rates remain unchanged over municipal or cooperative wholesale customers within the initial transition period (July 1, 2000 BGE's service territory. BGE's gas service territory through June 30, 2006), annual standard offer indudes an area of approximately 800 square miles. service rate increases are offset by corresponding BGE's electric and gas revenues come from many decreases in the CTC that BGE receives from customers-residential, commercial, and industrial. In its customers.
2004, BGE's largest electric customer provided
- While BGE does not sell electric commodity to approximately two percent of BGE's total electric all customers in its service territory, BGE revenues and BGE's largest gas customer provided continues to deliver electricity to all customers approximately one percent of BGE's total gas revenues. and provides meter reading, billing, emergency response, regular maintenance, and balancing Electric Business services.
Electric Regulatory 1fatters and Competition
- BGE transferred, at book value, its generating assets and related liabilities to the merchant Deregulation energy business. At December 31, 2004, BGE Effecive July 1, 2000, electric customer choice and remains contingently liable for the competition among electric suppliers was implemented in
$269.8 million outstanding balance for Maryland. As a result of the deregulation of electric liabilities transferred to the merchant energy generation, the following occurred.
business.
- All customers can choose their electric energy supplier.
StandardOffer Service
- BGE provided fixed-price standard offer service BGE provides fixed-price standard offer service for for commercial and industrial customers residential customers that do not select an alternative through either June 30, 2002 or June 30, 2004, supplier through June 30, 2006. Beginning July 1, depending on customer type. For the 2006, BGE's current obligation to provide fixed-price commercial and industrial customers that did standard offer service to residential customers ends, and not selea an alternative supplier after those all residential customers that receive their electric supply time periods, BGE provided a market-based standard offer service. Base rates for commercial from BGE will be charged market-based standard offer service rates, as discussed in the Standard Offer and industrial customers were frozen until Service-Protiderof Last Resort (POLR) section.
June 30, 2004.
9
BGE provided fixed-price standard offer service for Electric Load Management most of its large commercial and industrial customers BGE has implemented various programs for use when through June 30. 2002. The large commercial and system-operating conditions or market economics industrial customers that did not select an alternative indicate that a reduction in load would be beneficial.
supplier were provided market-based standard offer We refer to these programs as active load management service through June 30, 2004. BGE provided fixed- programs. These programs include:
price standard offer service to its remaining commercial
- two options for commercial and industrial and industrial customers through June 30, 2004. customers to voluntarily reduce their electric Beginning July 1, 2004, all commercial and industrial loads, customers that receive their electric supply from BGE
- air conditioning control for residential and are charged market-based standard offer service rates, as commercial customers, and discussed in the Standard Offer Service-Providerof Last
- residential water heater control.
Resort (POLR) section. These programs generally take effect on summer days when demand andlor wholesale prices are relatively Standard Offer Service-ProviderofLast Resort (POLR) high. These programs had the capability during the BGE is obligated to provide market-based standard offer 2004 summer to reduce load up to approximately 220 service to residential customers from July 1, 2006 MW.
through May 31, 2010, and for commercial and industrial customers for one, two, or four-year periods Transmission and Distribution Facilities beyond June 30, 2004, depending on customer load.
BGE maintains approximately 250 substations and The POLR rates charged during these time periods will 1,300 circuit miles of transmission lines throughout recover BGE's wholesale power supply costs and include central Maryland. BGE also maintains nearly 22,900 an administrative fee. The administrative fee indudes a circuit miles of distribution lines. The transmission shareholder return component and an incremental cost facilities are connected to those of neighboring utility component.
systems as part of the PJM Interconnection. Under the Bidding to supply BGE's standard offer service to PJM Tariff and various agreements, BGE and other commercial and industrial customers for one, two, or market participants can use regional transmission four-year periods beyond June 30, 2004, and to facilities for energy, capacity, and ancillary services residential customers beyond June 30, 2006, will occur transactions including emergency assistance.
from time to time through a competitive bidding We discuss various FERC initiatives relating to process approved by the Maryland PSC. Successful wholesale electric markets in more detail in Item 7.
bidders, which may indude affiliates of Constellation Managements Discussion and Analysis-FederalRegulation Energy, will execute contracts with BGE for varying section.
terms depending on the load being served under the contract.
We discuss the market risk of our regulated electric business in more detail in Item Z Management!
Discussion and Analysis-Market Risk section.
10
Electric Operating Statistics 2004 2003 2002 2001 2000
- Revenues (In mil/ians)
Residential $1,015.8 $ 959.0 $ 946.6 $ 885.3 $ 922.6 Commercial Excluding Delivery Service 708.9 694.2 776.0 903.0 926.2 Delivery Service Only 78.6 66.1 33.5 Industrial Exd uding Delivery Service 92.3 137.0 158.7 218.1 203.6 Delivery Service Only 21.3 18.2 10.9 System Sales 1,916.9 1,874.5 1,925.7 2,006.4 2,052.4 Interchange Sales 53.8 Other (A) 50.8 47.1 40.3 33.6 29.0 Total $1,967.7 $1,921.6 $1,966.0 $2,040.0 $2,135.2 Distribution Volumes (In thousands)-MWH Residential 13,313 12,754 12,652 11,714 11,675 Commercial Excluding Delivery Service 9,286 9,937 11,840 14,147 14,042 Delivery Service Only 5,767 4,982 2,762 -
Industrial Excluding Delivery Service 1,429 2,556 3,478 4,445 4,476 Delivery Service Only 2,562 1,780 997 - -
Total 32,357 32,009 31,729 30,306 30,193 Customers (In thousands)
Residential 1,072.1 1,061.7 1,052.3 1,040.5 1,033.4 Commercial 113.6 112.1 110.8 110.9 108.9 Industrial 4.8 4.9 4.9 5.0 5.0 Total 1,190.5 1,178.7 1,168.0 1,156.4 1,147.3 (A) Primarily includes transmission service integration revenues, late payment charges, miscellaneous service fees, and tower leasing revenues.
Operatingstatistics do not vflect the elimination of intercompany transactions.
7Delivery service only refrrs to BGE! delivery of commodity to customers that was purchased by the customer from an alternate supplier.
Gas Business For customers that buy their gas from BGE, there The wholesale price of natural gas as a commodity is is a market-based rates incentive mechanism. Under not subject to regulation. All BGE gas customers have market-based rates, our actual cost of gas is compared the option to purchase gas from alternative suppliers, to a market index (a measure of the market price of gas including subsidiaries of Constellation Energy. BGE in a given period). The difference between our actual continues to deliver gas to all customers within its cost and the market index is shared equally between service territory. This delivery service is regulated by the shareholders and customers. BGE must secure fixed-Maryland PSC. price contracts for at least 10%, but not more than BGE also provides customers with meter reading, 20%, of forecasted system supply requirements for the billing, emergency response, regular maintenance, and November through March period.
balancing services. BGE purchases the natural gas it resells to Approximately 50% of the gas delivered on BGE's customers directly from many producers and marketers.
distribution system is for customers that purchase gas BGE has transportation and storage agreements that from alternative suppliers. These customers are charged expire from 2005 to 2023.
fees to recover the costs BGE incurs to deliver the customers' gas through our distribution system.
11
BGE's current pipeline firm transportation during the summer months for operations of its entitlements to serve BGE's firm loads are 334,053 liquefied natural gas facility during peak winter periods.
dekatherms (DTH) per day during the winter period BGE historically has been able to arrange and 309,053 DTH per day during the summer period. short-term contracts or exchange agreements with other BGE's current maximum storage entitlements are gas companies in the event of short-term disruptions to 235,080 DTH per day. To supplement its gas supply at gas supplies or to meet additional demand.
times of heavy winter demands and to be available in BGE also participates in the interstate markets by temporary emergencies affecting gas supply, BGE has: releasing pipeline capacity or bundling pipeline capacity
- a liquefied natural gas facility for the with gas for off-system sales. Off-system gas sales are liquefaction and storage of natural gas with a low-margin direct sales of gas to wholesale suppliers of total storage capacity of 1,092,977 DTH and a natural gas outside BCES service territory. Earnings daily capacity of 311,500 DTH, and from these activities are shared between shareholders
- a propane air facility with a mined cavern with and customers. BGE makes these sales as part of a a total storage capacity equivalent to 564,200 program to balance our supply of, and cost of, natural DTH and a daily capacity of 85,000 DTH. gas.
BGE has under contract sufficient volumes of propane for the operation of the propane air facility and is capable of liquefring sufficient volumes of natural gas Gas Operating Statistics 2004 2003 2002 2001 2000 Revenues (In miliont)
Residential Excluding Delivery Service S 478.0 5 444.5 $ 342.1 $ 378.4 $ 328.4 Delivery Service Only 14.2 13.6 16.5 16.3 23.5 Commercial Excluding Delivery Service 135.4 128.6 89.4 115.5 97.9 Delivery Service Only 28.0 24.6 29.2 21.4 25.8 Industrial Excluding Delivery Service 9.4 11.5 9.3 12.8 10.9 Delivery Service Only 7.8 11.4 13.9 13.8 16.3 System Sales
- 672.8 634.2 500.4 558.2 502.8 Off.System Sales 77.2 84.8 74.8 113.6 101.0 Other 7.0 7.0 6.1 8.9 7.8 Total $ 757.0 $ 726.0 S 581.3 $ 680.7 $ 611.6 Distribution Volumes (In thouwnds)-DTH Residential Excluding Delivery Service 39,080 40,894 35.364 33,147 34,561 Delivery Service Only 6,053 6,640 6,404 7,201 9,209 Commercial Excluding Delivery Service 13,248 13,895 11,583 12,334 13,186 Delivery Service Only 34,120 29,138 28,429 25,037 22,921 Industrial Excluding Delivery Service 865 1,143 1,207 1,386 1,386 Delivery Service Only 14,310 18,399 23,689 23,872 32,382 System Sales 107,676 110,109 106,676 102,977 113,645 Off-System Sales 9,914 12,859 18,551 20,012 22.456 Total 117,590 122,968 125,227 122,989 136,101 Customers (In thousands)
Residential 582.0 575.2 567.3 558.7 553.7 Commercial 41.6 41.1 40.7 40.2 40.1 Industrial 1.2 1.2 1.3 1.4 1.4 Total 624.8 617.5 609.3 600.3 595.2 Operating statistics do not rcflct the elimination of intercompany transactions.
'Delivery sertice only refers to BGEs delivery of commodity to customers that was purchasedby the cstomerfrm an alternate supplier.
12
Franchises BGE has nonexclusive electric and gas franchises to use sufficient to permit them to engage in their present streets and other highways that are adequate and business. Conditions of the franchises are satisfactory.
Other Nonregulated Businesses Energy Projects and Services Other We offer energy projects and services designed primarily Our other nonregulated businesses include investments to provide energy solutions to large commercial and that we do not consider to be core operations. These industrial and governmental customers. These energy include financial investments, real estate projects, and products and services include: interests in a Panamanian distribution facility and in a
- designing, constructing, and operating heating, fund that holds interests in two South American energy cooling, and cogeneration facilities, projects. While our intent is to dispose of these assets,
- energy consulting and power-quality services, market conditions and other events beyond our control
- services to enhance the reliability of individual may affect the actual sale of these assets. In addition, a electric supply systems, and future decline in the fair value of these assets could
- customized financing alternatives. result in losses. We discuss these non-core assets in more detail in Item 7. Management: Discussion and Home Products and Gas Retail Marketing Analysis-Results of Operations section.
We offer services to customers in Maryland including:
- home improvements,
- the service of heating, air conditioning, plumbing, electrical, and indoor air quality systems, and
- the sale of natural gas to residential customers.
Consolidated Capital Requirements Our total capital requirements for 2004 were We continuously review and change our capital
$762 million. Of this amount, $497 million was used expenditure programs, so actual expenditures may vary in our nonregulated businesses and $265 million was from the estimate above. We discuss our capital used in our regulated business. We estimate our total requirements further in Item 7. Managements Discussion capital requirements will be $915 million in 2005. and Analysis-CapitalResources section.
Environmental Matters regulations. Our estimated environmental capital The development (involving site selection, requirements for the next three years are approximately environmental assessments, and permitting), $5 million in 2005, $45 million in 2006, and construction, acquisition, and operation of electric $80 million in 2007.
generating and distribution facilities are subject to extensive federal, state, and local environmental and Air Quality land use laws and regulations. From the beginning The Clean Air Act created the basic framework for the phases of development to the ongoing operation of federal and state regulation of air pollution. The existing or new electric generating and distribution cornerstone of the Act is the requirement that National facilities, our activities involve compliance with diverse Ambient Air Quality Standards be established to protect laws and regulations that address emissions and impacts public health and public welfare. In addition, the Act to air and water, protection of natural and cultural also indudes technology-driven emission requirements.
resources, and chemical and waste handling and Many of these provisions could materially affect our disposal. facilities and are described in more detail below.
We continuously monitor federal, state, and local environmental initiatives to determine potential impacts National Ambient Air Quality Standards (NAAQS) on our financial results. As new laws or regulations are The NAAQS are federal air quality standards that promulgated, we assess their applicability and establish maximum ambient air concentrations for the implement the necessary modifications to our facilities following specific pollutants: ozone (smog), carbon or their operation to maintain on-going compliance. monoxide, lead, particulates, sulfur dioxides (SO2), and Our capital expenditures were approximately nitrogen dioxides (NO2). Our generating facilities are
$235 million during the five-year period 2000-2004 to primarily affected by ozone and parriculates standards.
comply with existing environmental standards and Ozone is formed when sunlight interacts with emissions 13
of nitrogen oxides (NOx) and volatile organic emissions as compared to its emissions when the area compounds (such as from motor vehicle exhaust). Our failed to meet the deadline. The exact method of generating facilities are subject to various permits and computing these fees has not been established and will programs meant to achieve or preserve attainment of depend in part on state implementation regulations that the standards for all these pollutants. have not been finalized.
In order for states to achieve compliance with the There are various deadlines for Maryland and NAAQS, federal and/or state legislation or regulation is California to meet the NAAQS for ozone with the likely to be adopted that will require additional earliest being November 2005. Assessment of fees would emission reductions from our facilities. The commence in 2006 if the current effective dates are Environmental Protection Agency (EPA) has proposed maintained. However, there is significant uncertainty the Clean Air Interstate Rule (CAIR) to further reduce regarding the date when fees would be assessed and SO 2 and NOx emissions by addressing the interstate whether they would be applicable to our facilities transport of SO 2and NOx emissions from fossil because the EPA is involved in litigation regarding these fuel-fired plants located primarily in the Eastern United issues. Consequently, we are unable to estimate the States. In addition to CAIR, the Bush Administration is ultimate applicability, timing or financial impact of the proposing a legislative approach (Clear Skies) which fees in light of the uncertainty surrounding the effective would require similar reductions in emissions of SO 2 dates and the methodology that will be used in and NOx. Depending on the timing and requirements calculating the fees.
of any federal proposal, one or more states in which we operate may impose more stringent or earlier emission HazardousAir Emissions The Clean Air Act requires the EPA to evaluate the reduction requirements. We favor the Clear Skies public health impacts of hazardous air emissions from approach to achieve future emission reductions as the electric steam generating facilities. In December 2003, fairest and most expeditious manner in which to meet the EPA proposed to regulate the emissions of mercury the NAAQS.
from coal-fired facilities and nickel from residual As a result of these regulatory and legislative oil-fired facilities. Under the mercury proposal, the EPA proposals, along with new rules to impose limits on has proposed compliance alternatives, including a unit hazardous substances, we expect more stringent air specific standard and a cap and trade program. As emission standards to be adopted. If new requirements proposed, compliance with the unit specific limits are promulgated as expected we will install additional would be required as early as March 2008, but could be air emission control equipment at our coal-fired delayed for at least one year as allowed under the generating facilities in Maryland and at our co-owned proposed requirements. Compliance with the mercury coal-fired facilities in Pennsylvania to meet air quality standards. We indude in our estimated environmental cap and trade program would be required by January 2010. The Bush Administration's Clear Skies capital requirements capital spending for these projects, legislative proposal also addresses regulation of mercury which we expect will be approximately $2 million in through a cap and trade approach. The nickel emission 2005. $32 million in 2006, and $75 million in 2007. If limits for residual oil-fired facilities would require these rules are promulgated as we have assumed in our compliance by March 2008 but could be delayed for at projections, we will spend another $400-$500 million of capital from 2008-2010. Our estimates are subject to least one year as allowed under the proposed requirements. We believe final regulations could be significant uncertainties including the timing of any issued in 2005 and could affect all coal and oil-fired regulatory or legislative change, its implementation boilers at our generating facilities. The cost of timetable, and the amount of emissions reductions that compliance with the final regulations could be material.
will be required. As a result, we cannot predict our capital spending or the scope or timing of these projects New Source Review with certainty, and the actual expenditures, scope and The EPA and several states filed lawsuits against a timing could differ significantly from our estimates. number of coal-fired power plants primarily in On March 10, 2005, the EPA adopted CAIR We Mid-Western and Southern states alleging violations of are in the process of evaluating the impact of the rules the Prevention of Significant Deterioration and on our financial results. Non-Attainment provisions of the Clean Air Ac's new We own several generating facilities in Maryland source review requirements. The EPA requested and California, states that do not meet the NAAQS for information relating to modifications made to our ozone. The Clean Air Act requires states to assess fees Brandon Shores, Crane, and Wagner plants located in against every major stationary source of NOx and Maryland. The EPA also sent similar, but narrower, volatile organic compounds in areas that have not met information requests to two of our newer Pennsylvania the NAAQS for ozone if the NAAQS is not achieved waste-coal burning plants in which we have an by a specified deadline. If implemented, the fees would ownership interest. We have responded to the EPA, and be assessed based on the magnitude of a source's 14
as of the date of this report the EPA has taken no or other protective measures, as well as extensive further action. site-specific study and monitoring requirements. We Based on the level of emissions control that the currently have six facilities affected by the regulation.
EPA and states are seeking in these new source review The rule allows for a number of compliance options enforcement actions, we believe that material additional that will be assessed through 2007, following which we costs and penalties could be incurred, and planned will determine whether any action is required and what capital expenditures could be accelerated, if the EPA our most viable options are if any action is required.
was successful in any future actions regarding our Until we determine our most viable option under the facilities. final rules, we cannot estimate our compliance costs.
In August 2003. the EPA's equipment replacement However, the costs associated with the final rules could rule was promulgated. The rule establishes an be material.
equipment replacement cost threshold for determining when major new source review requirements are Hazardous and Solid Waste triggered. The rule provides that plant owners may The Comprehensive Environmental Response, spend up to 20% of the replacement value of a Compensation and Liability Act (CERCLA) established generation unit on certain component replacements the basic framework for federal and state regulations each year without triggering requirements for new that can require any individual or entity that may have pollution controls. A legal challenge to this rule was owned or operated a disposal site, as well as transporters filed with the United States Court of Appeals and a stay or generators of hazardous substances sent to such site, Dwas issued which delayed its effective date. The EPA to share in remediation costs. Except to the extent has also determined to seek additional comment on discussed in Note 12 to the ConsolidatedFinancial certain features of the rule, including the 20% Statements, compliance with CERCLA requirements is threshold. We cannot predict the timing or outcome of not expected to have a material adverse effect on our the legal challenge or the EPA comment process, or financial results.
their possible effect on our financial results. The Resource Conservation and Recovery Act (RCRA) gives the EPA authority to control hazardous Global Climate Change waste from "cradle-to-grave." This includes the Future initiatives regarding greenhouse gas emissions generation, transportation, treatment, storage, and and global warming continue to be the subject of much disposal of hazardous waste. RCRA also sets forth a debate. As a result of our diverse fuel portfolio, our framework for the management of non-hazardous contribution to greenhouse gases varies by plant type.
wastes. Although RCRA focuses only on active and Fossil fuel-fired power plants are significant sources of future facilities and, unlike CERCLA, does not address carbon dioxide emissions, a principal greenhouse gas.
abandoned or historical sites, there are provisions that Our compliance costs with any mandated federal require phasing-out land disposal of hazardous waste, greenhouse gas reductions in the future could be more stringent hazardous waste management standards, material.
and a comprehensive underground storage tank program.
pwater Quality Our coal-fired generating facilities produce The Clean Water Act established the basic framework approximately two million tons of combustion for federal and state regulation of water pollution by-products ("ash) each year, including approximately control. The Act requires facilities that discharge waste 700,000 tons at our Maryland plants. Of the two or storm water into the waters of the United States to million tons, approximately half is beneficially re-used obtain permits requiring them to meet effluent limits in in various projects, including as structural fill in surface order to achieve ambient water quality standards in the mine reclamation, and half is placed in landfills. In receiving waters. Under current provisions of the Clean 2000, the EPA decided not to regulate combustion ash Water Act, existing discharge permits are renewed every as a hazardous waste under RCRA. Instead, the EPA five years, at which time permit effluent limits come announced its intention to develop national standards, under extensive review and can be modified to account currently scheduled to be proposed in April 2006, to for more stringent regulations. In addition, the permits regulate this material as a non-hazardous waste, and is can be modified at any time.
developing regulations governing the placement of ash Water Intake Regulations in landfills, surface impoundments, and sand/gravel In July 2004, the EPA published final rules under the surface mines. The EPA is also developing regulations Clean Water Act that require cooling water intake for ash placement in coal mines, which are expected to structures to reflect the best technology available for be proposed in October 2007. Federal regulation has minimizing adverse environmental impacts. The final the potential to result in additional requirements such rules require the installation of additional intake screens as groundwater monitoring, liners, and leachate 15
collection and treatment systems for all landfills, surface and the scope of the final requirements. As a result, we impoundments, and sand and gravel mines used for ash cannot predict our capital spending or the scope and management. Depending on the scope of any final timing of this project with certainty, and the actual requirements, our compliance costs could be material. expenditures, scope and timing could differ significantly As a result of these regulatory proposals, the from our estimates.
remaining ash placement capacity at our current mine reclamation site and our current ash generation Employees projections, we are exploring our options for the Constellation Energy and its subsidiaries had placement of ash, induding construction of an ash approximately 9,570 employees at December 31, 2004.
placement facility. Over the next five years, we estimate At the Nine Mile Point plant, approximately 700 that our capital expenditures for this project will be as employees are represented by the International follows: approximately $10 million in 2006 and, if we Brotherhood of Electrical Workers, Local 97. The labor decide to construct a facility, approximately $55 million contract with this union expires in June 2006. We in 2008 towards the purchase of land. Our estimates are believe that our relationship with this union is subject to significant uncertainties including the timing satisfactory, but there can be no assurances that this will of any regulatory change, its implementation timetable, continue to be the case.
16
Item 2. Properties expiration of the rights-of-way does not affect BGE's Constellation Energy's corporate offices occupy ability to use the rights-of-way during the renewal approximately 106,000 square feet of leased office space process.
in Baltimore, Maryland. The corporate offices for most BGE has electric transmission and electric and gas of our merchant energy business occupy approximately distribution lines located:
172,000 square feet of leased office space in another
- in public streets and highways pursuant to building in Baltimore, Maryland. We describe our franchises, and electric generation properties on the next page. We also
- on rights-of-way secured for the most part by have leases for other offices and services located in the grants from owners of the property.
Baltimore metropolitan region, and for various real All of BGE's property is subject to the lien of property and facilities relating to our generation BGE's mortgage securing its mortgage bonds. All of the projects. generation facilities transferred to affiliates by BGE on BGE's principal headquarters building is located in July 1, 2000, along with the stock we own in certain of downtown Baltimore. In January 2004, BGE sold a our subsidiaries, are subject to the lien of BGE's portion of its headquarters building and is in the mortgage.
process of consolidating its operations into the We believe we have satisfactory title to our power remainder of the building. In addition, BGE owns project facilities in accordance with standards generally propane air and liquefied natural gas facilities as accepted in the energy industry, subject to exceptions, discussed in Item 1. Business-Gas Business section. which in our opinion, would not have a material BGE also has rights-of-way to maintain 26-inch adverse effect on the use or value of the facilities.
natural gas mains across certain Baltimore City-owned We also lease office space throughout North property (principally parks) which expired in 2004. America, in the United Kingdom, and in Australia to BGE is in the process of renewing the rights-of-way support our merchant energy business.
with Baltimore City for an additional 25 years. The 17
Ile following table describes our generating facilities:
Installed % Capacity Primary Plant Location Capaciry(MW) Owned Owned (MNW) Fucl (at December 31, 2004)
Afid-Atlanti Rftion Calvert Cliffs Calvert Co., MD 1,735 100.0 1,735 Nuclear Brandon Shores Anne Arundel Co., MD 1,286 100.0 1,286 Coal H. A Wagner Anne Arundel Co., MD 1,009 100.0 1,009 Coal/Oil/Gas C. P.Crane Baltimore Co., MD 399 100.0 399 Oil/Coal Keystone Armstrong and Indiana Cos., PA 1,711 21.0 359 (A) Coal Conernaugh Indiana Co., PA 1,711 10.6 181 (A) Coal Perrynan Harford Co., MD 360 100.0 360 Oil/Gas Riverside Baltimore Co., MD 249 100.0 249 Oil/Gas Handsome Lake Rockland Twp, PA 250 100.0 250 Gas Notch Cliff Baltimore Co., MD 128 100.0 128 Gas Westport Baltimore City, MD 121 100.0 121 Gas Philadelphia Road Baltimore City MD 64 100.0 64 Oil Safe Harbor Safe Harbor, PA 416 66.7 277 Hydro Total Jlid-Atlantie Region 9.439 6,418 Prnts with elever PurchaseArremens High Desert Victorvillc, CA 830 100.0 830 Gas Nine Mile Point Unit I Scriba, NY 609 100.0 609 Nudear Nine Mile Point Unit 2 Scriba, NY 1,148 82.0 941 Nudcear R.E. Ginna Ontario, NY 495 100.0 495 Nuclear Oleander Brevard Co., FL 680 100.0 680 Oil/Gas University Park Chicago, IL 300 100.0 300 Gas Total Plants with Power PurrhaseAgreements 4.062 3,855 Coemeritive Suapin Rio Nogales Seguin, TX 800 100.0 800 Gas Holland Energy Shelby Co., IL 665 100.0 665 Gas Big Sandy Ncl, WV 300 100.0 300 Gas Wolf Hills Bristol, VA 250 100.0 250 Gas Total Competitive Supply 2,015 2,015 Other Panther Creek Ncsquehoning, PA 83 50.0 42 Waste Coal Colver Colver Township, PA 110 25.0 28 Waste Coal Sunnyside Sunnyside. UT 53 50.0 26 Waste Coal ACE Trona, CA 102 31.1 31 Coal Jasmin Kern Co., CA 33 50.0 17 Coal POSO Kern Co., CA 33 50.0 17 Coal Mammoth Lakes G-l Mammoth Lakes, CA 8 50.0 4 Geothermal Mammoth Lakes G-2 Mammoth Lakes, CA 12 50.0 6 Geothermal Mammoth Lakes G-3 Mammoth Lakes, CA 12 50.0 6 Geothermal Soda Lake I Fallon, NV 3 50.0 2 Geothermal Soda Lake 11 Fallon, NV 13 50.0 7 Geothermal Rocklin Placer Co., CA 24 50.0 12 Biomass Fresno Fresno, CA 24 50.0 12 Biomass Chinese Srarion Sonora. CA 22 45.0 10 Biomass Mal6cha Muck Valley, CA 32 50.0 16 Hydro SEGS IV Kramer Junction, CA 30 12.0 4 Solar SEGS V Kramer Junction, CA 30 4.0 Solar SEGS VI Kramer Junction, CA 30 9.0 3 Solar Total Other 654 244 Total GeneratingFacilitie, 16,170 12,532 (A) Reflects our proportionate interest in and entitlement to capacity from Keystone and Conemaugh. which include 2 megawatts of diesel c2pacity for Keystone and I megawatt of diesel capacity for Conemaugh.
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The following table describes our processing facilities:
Primary Plant Location Owned Fuel A/C Fuels Hazelton, PA 50.0 Coal Processing Gary PCI Gary. IN 24.5 Coal Processing Low Country Cross, SC 99.0 Synfuel Processing PC Synfuel VA I Appalachia, VA 16.7 Synfuel Processing PC Synfuel WV I Charleston, WV 16.7 Synfuel Processing PC Synfuel WV 11 Mount Storm, WV 16.7 Synfuel Processing PC Synfucl WV III Mayberry, WV 16.7 Synfuel Processing Item 3. Legal Proceedings We discuss our legal proceedings in Notr 12 to ConsolidatedFinancialStatements.
Item 4. Submission of Matters to Vote of Security Holders Not applicable.
Executive Officers of the Registrant Other Offices or Positions Held Name Age Present Office During Past Five Years Mayo A. Shattuck III 50 Chairman of the Board of Constellation Global Head of Investment Banking and Energy (since July 2002), President Global Head of Private Banking-and Chief Executive Officer of Deutsche Bane Alex. Brown; and Vice Constellation Energy (since November Chairman-Bankers Trust 2001); and Chairman of the Board of Corporation.
BGE (since July 2002)
E. Follin Smith 45 Executive Vice President (since January Senior Vice President-Constellation 2004) and Chief Financial Officer Energy; Senior Vice President and (since June 2001) and Chief Chief Financial Officer-Armstrong Administrative Officer (since Holdings, Inc.; Vice President and December 2003) of Constellation Treasurer-Armstrong Holdings, Inc.
Energy and Senior Vice President and (filed for bankruptcy under Chief Financial Officer of Baltimore Chapter 11 on December 6, 2000);
Gas and Electric Company (since and Chief Financial Officer-General January 2002) Motors-Delphi Chassis Systems.
Thomas V. Brooks 42 President of Constellation Energy Vice President of Business Development Commodities Group, Inc. (formerly and Strategy-Constellation Energy; Constellation Power Source, Inc.) and Vice President-Goldman Sachs.
(since October 2001); Executive Vice President of Constellation Energy (since January 2004)
Michael J. Wallace 57 President of Constellation Generation Managing Director and Member-Group, LLC (since January 2002); Barrington Energy Partners; and Executive Vice President of Senior Vice President-Constellation Energy (since January Commonwealth Edison.
2004)
Thomas F.Brady 55 Executive Vice President, Corporate Senior Vice President, Corporate Strategy and Retail Competitive Strategy and Development-Supply of Constellation Energy (since Constellation Energy, Vice President, January 2004) Corporate Strategy and Development-Constellation Energy, and Vice President, Corporate Strategy and Development-BGE.
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Other Offices or Positions field Name Age Present Office During Past Five Years Kenneth W. DeFontes. Jr. 54 President and Chief Executive Officer of Vice President, Electric Transmission Baltimore Gas and Electric Company and Distribution-BGE; and and Senior Vice President of Manager, Corporate Strategy and Constellation Energy (since October Development-Constellation Energy.
2004)
Paul J. Allen 53 Senior Vice President, Corporate Affairs Vice President, Corporate Affairs-of Constellation Energy (since January Constellation Energy; and Senior Vice 2004) President and Group Head-Ogilvy Public Relations.
John R. Collins 47 Senior Vice President (since January Vice President-Constellation Energy; 2004) and Chief Risk Officer of Managing Director-Finance-Constellation Energy (since December Constellation Power Source 2001) Holdings, Inc.; and Senior Financial Officer-Constellation Power Source, Inc.
Beth S. Perlman 44 Senior Vice President (since January Vice President. Technology-Enron 2004) and Chief Information Officer Corporation.
of Constellation Energy (since April 2002)
Marc L. Ugol 46 Senior Vice President, Human Resources Vice President, Human Resources-of Constellation Energy (since January Constellation Energy; Senior Vice 2004) President, Human Resources and Administration-Tellabs, Inc.; and Senior Vice President, Human Resources-Platinum Technology International.
Officers are elected by, and hold office at the will of, the Board of Directors and do not serve a 'term of office" as such. There is no arrangement or understanding between any director or officer and any other person pursuant to which the director or officer was selected.
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PART II Item 5. Market for Registrant's Common Equity and Related Shareholder Matters Stock Trading In January 2005, we announced an increase in our Constellation Energy's common stock is traded under quarterly dividend from S0.285 to S0.335 per share on the ticker symbol CEG. It is listed on the New York, our common stock payable April 1, 2005 to holders of Chicago, and Pacific stock exchanges. It has unlisted record on March 10, 2005. This is equivalent to an trading privileges on the Boston, Cincinnati, and annual rate of $1.34 per share.
Philadelphia exchanges. Quarterly dividends were declared on our common As of February 28, 2005, there were 45,843 stock during 2004 and 2003 in the amounts set forth common shareholders of record. below.
BGE pays dividends on its common stock after its Dividend Policy Board of Directors declares them. There are no Constellation Energy pays dividends on its common contractual limitations on BGE paying common stock stock after its Board of Directors declares them. There dividends unless:
are no contractual limitations on Constellation Energy
- BGE elects to defer interest payments on the paying common stock dividends. 6.20% Deferrable Interest Subordinated Dividends have been paid continuously since 1910 Debentures due 2043, and any deferred interest on the common stock of Constellation Energy, BGE, remains unpaid; or and their predecessors. Future dividends depend upon
- any dividends (and any redemption payments) future earnings, our financial condition, and other due on BGE's preference stock have not been factors. paid.
Common Stock Dividends and Price Ranges 2004 2003 Dividend Price* Dividend Price' Dedared High LOw Declared High Lrw First Quarter .$0.285 $41.47 $38.52 $0.260 $30.23 $25.17 Second Quarter.0.285 41.35 35.89 0.260 34.92 27.50 Third Quarter.0.285 41.18 36.76 0.260 37.65 31.75 Fourth Quarter.0.285 44.90 39.90 0.260 39.61 35.03 Total .$1140 $ 1.040
- Based on New York Stock Exchange Composite Transactions.
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Item 6. Selected Financial Data Constellation Energy Group, Inc. and Subsidiaries 2004 2003 2002 2001 2000 (In millions, except per share amounts)
Summary of Operations Total Revenues $12,549.7 $ 9,687.8 $ 4,718.6 $ 3.877.3 $ 3,772.5 Total Expenses 11,471.3 8,647.7 3,893.7 3,525.7 3,008.0 Net (Loss) Gain on Sales of Investments and Other Assets (1.2) 26.2 261.3 6.2 78.1 Income From Operations 1,077.2 1,066.3 1,086.2 357.8 842.6 Other Income 14.1 19.1 30.5 1.3 4.2 Fixed Charges 330.3 340.2 281.5 238.8 271.4 Income Before Income Taxes 761.0 745.2 835.2 120.3 575.4 Income Taxes 172.2 269.5 309.6 37.9 230.1 Income from Continuing Operations and Before Cumulative Effects or Changes in Accounting Principles 588.8 475.7 525.6 82.4 345.3 Loss from Discontinued Operations, Net of Income Taxes (49.1) - - - -
Cumulative Effects of Changes in Accounting Principles, Net of Income Taxes - (198.4) - 8.5 Net Income $ 539.7 $ 277.3 $ 525.6 $ 90.9 $ 345.3 Earnings Per Common Share from Continuing Operations and Before Cumulative Effects of Changes in Accounting Principles Assuming Dilution $ 3.40 $ 2.85 $ 3.20 $ 0.52 S 2.30 Loss from Discontinued Operations (0.28) - - - -
Cumulative Effects of Changes in Accounting Principles - (1.19) - 0.05 Earnings Per Common Share Assuming Dilution $ 3.12 $ 1.66 $ 3.20 $ 0.57 $ 2.30 Dividends Declared Per Common Share $ 1.14 $ 1.04 $ 0.96 $ 0.48 $ 1.68 Summary of Financial Condition Total Assets $17,347.1 $15,593.0 $14,943.3 $14,697.5 $13,248.1 Short-Term Borrowings $ - $ 9.6 $ 10.5 $ 975.0 $ 243.6 Current Portion of Long-Term Debt $ 480.4 $ 343.2 $ 426.2 $ 1,406.7 $ 906.6 Capitalization Long-Term Debt S 4,813.2 $ 5,039.2 $ 4,613.9 $ 2,712.5 $ 3,159.3 Minority Interests 90.9 113.4 105.3 101.7 97.7 Preference Stock Not Subject to Mandatory Redemption 190.0 190.0 190.0 190.0 190.0 Common Shareholders' Equity 4,726.9 4,140.5 3,862.3 3,843.6 3,174.0 Total Capitalization $ 9,821.0 $ 9,483.1 $ 8,771.5 $ 6,847.8 $ 6,621.0 Financial Statistics at Year End Ratio of Earnings to Fixed Charges 3.11 2.98 3.33 1.18 2.78 Book Value Per Share of Common Stock $ 26.81 $ 24.68 $ 23.44 $ 23.48 $ 21.09 Certainprior-year amounts have been reclassifiedto conformn with the curntyearspresentation.
We discuss items that affect comparability between years, including acquisitions, accounting changes, including the impact of adopting Emerging Issues Task Force Issue (EITF) 02-3, Issues Involved in Accountingfor Derivative Contracts Heldfor Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities, and special items, in Item 7. Managements Discussion and Analysis.
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Baltimore Gas and Electric Company and Subsidiaries 2004 2003 2002 2001 2000 (In milloni)
Summary of Operations Total Revenues $2,724.7 $2,647.6 $2,547.3 $2,720.7 $2,746.8 Total Expenses 2,353.3 2,262.6 2,181.0 2,408.9 2,334.4 Income From Operations 371.4 385.0 366.3 311.8 412.4 Other (Expense) Income (6.4) (5.4) 10.7 0.4 7.5 Fixed Charges 96.2 111.2 140.6 154.6 184.0 Income Before Income Taxes 268.8 268.4 236.4 157.6 235.9 Income Taxes 102.5 105.2 93.3 60.3 92.4 Net Income 166.3 163.2 143.1 97.3 143.5 Preference Stock Dividends 13.2 13.2 13.2 13.2 13.2 Earnings Applicable to Common Stock $ 153.1 $ 150.0 $ 129.9 $ 84.1 $ 130.3 Summary of Financial Condition Total Assets $4,662.9 $4,706.6 $4.779.9 $4,954.5 $4.657.4 Short-Term Borrowings $ - $ - $ - $ - $ 32.1 Current Portion of Long-Term Debt $ 165.9 $ 330.6 $ 420.7 $ 666.3 $ 567.6 Capitalization Long-Term Debt $1,359.5 $1,343.7 $1,499.1 $1,821.7 $1,864.4 Minority Interest 18.7 18.9 19.4 5.0 4.6 Preference Stock Not Subject to Mandatory Redemption 190.0 190.0 190.0 190.0 190.0 Common Shareholder's Equity 1,566.0 1,487.7 1,461.7 1,131.4 802.3 Total Capitalization $3,134.2 $3,040.3 $3,170.2 $3,148.1 $2,861.3 Financial Statistics at Year End Ratio of Earnings to Fixed Charges 3.75 3.36 2.66 1.99 2.27 Ratio of Earnings to Fixed Charges and Preferred and Preference Stock Dividends 3.08 2.82 2.31 1.75 2.03 23
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations Introduction and Overview Strategy Constellation Energy Group, Inc. (Constellation Energy) is a We are pursuing a strategy of distributing energy and energy North American energy company that conducts its business related services through our competitive supply activities and through various subsidiaries including a merchant energy BGE, our regulated utility located in Maryland. Our merchant business and Baltimore Gas and Electric Company (BGE). We energy business focuses on short-term and long-term, high-value describe our operating segments in Note 3. sales of energy, capacity, and related products to various This report is a combined report of Constellation Energy customers, including distribution utilities, municipalities, and BGE. References in this report to "we" and "our" are to cooperatives, industrial customers, and commercial customers Constellation Energy and its subsidiaries, collectively. References primarily in the regional markets in which end-use customer in this report to the 'regulated business(es)" are to BGE. We electricity and gas rates have been deregulated and thereby discuss our business in more detail in Item 1. Business section. separated from the cost of generation and gas supply. These In this discussion and analysis, we will explain the general markets include:
financial condition and the results of operations for
- the Northeast (New England and New York),
Constellation Energy and BGE including:
- the Mid-Atlantic and Midwest regions,
- factors which affect our businesses,
- the West region (Texas and California), and
- our earnings and costs in the periods presented,
- certain areas in Canada.
- changes in earnings and costs between periods, We obtain this energy through both owned and contracted
- sources of earnings, supply resources. Our generation fleet is strategically located in
- impact of these factors on our overall financial deregulated markets across the country and is diversified by fuel type, including nuclear, coal, gas, oil, and renewable sources.
condition, Where we do not own generation, we contract for power from
- expected future expenditures for capital projects, and other merchant providers, typically through power purchase
- expected sources of cash for future capital expenditures.
agreements. Wc intend to remain diversified between regulated As you read this discussion and analysis, refer to our transmission and distribution and competitive supply. We will Consolidated Statements of Income, which present the results of use both our owned generation and our contracted generation to our operations for 2004, 2003, and 2002. Our results reflect a support our competitive supply operations.
significant increase in revenues and in purchased fuel and energy We are a leading national competitive supplier of energy in expenses mainly due to the implementation of Emerging Issues the deregulated markets previously discussed. In our wholesale Task Force Issue (EITF) 02-3, Issues Involved in Accountingfor and commercial and industrial retail marketing activities we are Derivative Contracut Heldfi/r TradingPurposes and Contracats leveraging our recognized expertise in providing full requirements Involved in Energy Trading and Risk Management Activities in energy and energy related services to enter markets, capture January 2003, as well as the full year impact of our 2002 market share, and organically grow these businesses. Through the acquisitions. We discuss our acquisitions in more detail in Nrote 15. application of technology, intellectual capital, process We analyze and explain the differences between periods in the improvement, and increased scale, we are seeking to reduce the specific line items of our Consolidated Statements of Income. cost of delivering full requirements energy and energy related We have organized our discussion and analysis as follows: services and managing risk.
- First, we discuss our strategy. We are also responding proactively to customer needs by
- We then describe the business environment in which we expanding the variety of products we offer. Our wholesale operate including how regulation, weather, and other competitive supply activities include a growing customer factors affect our business. products operation that markets physical energy products and
- Next, we discuss our critical accounting policies. These risk management and logistics services to generators, distributors, are the accounting policies that are most important to producers of coal, natural gas and fuel oil, and other consumers.
both the portrayal of our financial condition and results Within our retail competitive supply activities, we are of operations and require management's most difficult, marketing a broader array of products and expanding our subjective or complex judgment. markets. Over time, we may consider integrating the sale of
- We highlight significant events that are important to electricity and natural gas to provide one energy procurement understanding our results of operations and financial solution for our customers.
condition. Collectively, the integration of owned and contracted
- We then review our results of operations beginning with electric generation assets with origination, fuel procurement, and an overview of our total company results, followed by a risk management expertise, allows our merchant energy business more detailed review of those results by operating to earn incremental margin and more effectively manage energy segment. and commodity price risk over geographic regions and over time.
- We review our financial condition addressing our Our focus is on providing solutions to customers' energy needs, sources and uses of cash, security ratings, capital and our wholesale marketing and risk management operation resources, capital requirements, commitments, and adds value to our owned and contracted generation assets by off-balance sheet arrangements. providing national market access, market infrastructure, real-time
- WVe conclude with a discussion of our exposure to market intelligence, risk management and arbitrage various market risks. opportunities, and transmission and transportation expertise.
Generation capacity supports our wholesale marketing and risk management operation by providing a source of reliable power supply that provides a physical hedge for some of our load-serving activities.
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To achieve our strategic objectives, we expect to continue to Electric Competition pursue opportunities that expand our access to customers and to We face competition in the sale of electricity in wholesale power support our wholesale marketing and risk management operation markets and to retail customers.
with generation assets that have diversified geographic, fuel, and Various states have moved to restructure their electricity dispatch characteristics. We also expect to grow organically markets. The pace of deregulation in these states varies based on through selling a greater number of physical energy products and historical moves to competition and responses to recent market services to large energy customers. We expect to achieve events. While many states continue their support for retail operating efficiencies within our competitive supply operation competition and industry restructuring, other states that were and our generation fleet by selling more products through our considering deregulation have slowed their plans or postponed existing sales force, benefiting from efficiencies of scale, adding consideration. In addition, other states are reconsidering to the capacity of existing plants, and making our business deregulation. We discuss merchant competition in more detail in processes more efficient. Item 1. Business-Competition section.
We expect BGE and our other retail energy service The impacts of electric deregulation on BGE in Maryland businesses to grow through focused and disciplined expansion are discussed in Item 1. Business-ElectricRegulatory Matters and primarily from new customers. At BGE, we are also focused on Competition section.
enhancing reliability and customer satisfaction.
Customer choice, regulatory change, and energy market Gas Competition conditions significantly impact our business. In response, we The wholesale price of natural gas is not subject to regulation.
regularly evaluate our strategies with these goals in mind: to All BGE gas customers have the option to purchase gas from improve our competitive position, to anticipate and adapt to the alternate suppliers.
business environment and regulatory changes, and to maintain a strong balance sheet and investment-grade credit quality. Regulation by the Maryland PSC We are constantly reevaluating our strategies and might In addition to electric restructuring which was discussed in Item consider: 1. Business-Electric Regulatory Matters and Competition section,
- acquiring or developing additional generating facilities to regulation by the Maryland Public Service Commission support our merchant energy business, (Maryland PSC) significantly influences BGE's businesses. The
- mergers or acquisitions of utility or non-utility Maryland PSC determines the rates that BGE can charge businesses or assets, and customers for the electric distribution and gas businesses. The
- sale of assets or one or more businesses. Maryland PSC incorporates into BGE's electric rates the transmission rates determined by the Federal Energy Regulatory Commission (FERC). BGE's electric rates are unbundled in Business Environment General Industry customer billings to show separate components for delivery Over the past several years, the utility industry and energy service (i.e. base rates), competitive transition charges, electric markets experienced significant changes as a result of less liquid supply (commodity charge), transmission, a universal service and more volatile wholesale markets, credit quality deterioration surcharge, and certain taxes. The rates for BGE's regulated gas of various industry participants, and the slowing of the U.S. business continue to consist of a delivery charge (base rate) and economy. a commodity charge.
The energy markets also were affected by other significant events, including expanded investigations by state and federal Base Rates authorities into business practices of energy companies in the The base rate is the rate the Maryland PSC allows BGE to deregulated power and gas markets relating to 'wash trading" to charge its customers for the cost of providing them delivery inflate revenues and volumes, and other trading practices service, plus a profit. BGE has both an electric base rate and a designed to manipulate market prices. In addition, several gas base rate. Higher electric base rates apply during the summer merchant energy businesses significantly reduced their energy when the demand for electricity is higher. Gas base rates are not trading activities due to deteriorating credit quality. affected by seasonal changes.
Over the last few years, the energy markets have been BGE may ask the Maryland PSC to increase base rates highly volatile with significant changes in natural gas and power from time to time. The Maryland PSC historically has allowed prices, as well as the continuation of reduced liquidity in the BGE to increase base rates to recover its utility plant investment marketplace. We continue to actively manage our credit portfolio and operating costs, plus a profit, beginning at the time of to attempt to reduce the impact of a potential counterparty replacement. Generally, rate increases improve the earnings of default. We discuss our customer (counterparty) credit and other our regulated business because they allow us to collect more risks in more detail in the Market Risk section. revenue. However, rate increases are normally granted based on We also continue to examine plans to achieve our strategies historical data, and those increases may not always keep pace and to further strengthen our balance sheet and enhance our with increasing costs. Other parties may petition the Maryland liquidity. We discuss our liquidity in the FinancialCondition PSC to decrease base rates.
section.
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As a result of the deregulation of electric generation in implement measures to mitigate the market power in order to Maryland. BGE's residential electric base rates are frozen until maintain market-based rate authority. In addition, FERC is July 2006. Electric base rates were frozen until July 2004 for reviewing other aspects of its granting of market-based rate commercial and industrial customers. We discuss electric authority, including transmission market power, affiliate abuse, deregulation in Item 1. Business-Ekctric Regulatory Matters and and barriers to entry. We cannot determine the eventual Competition section. outcome of FERC's efforts in this regard and their impact on our financial results at this time.
Electric Commodity and Transmission Charges In January 2005, BGE and other transmission owners filed a BGE electric commodity and transmission charges (standard joint application at FERC to have network transmission rates offer service) are discussed in Item 1. Business-Electric Regulatory established through a formula that tracks costs instead of through Matters and Competition section. fixed rates in accordance with FERC guidelines. If accepted by FERC, the formula approach would take effect in June 2005, and Gas Commodity Charge transmission rates would be adjusted in June of each year based BGE charges its gas customers separately for the natural gas they on the formula without the need for another transmission rate purchase. The price BGE charges for the natural gas is based on filing. We cannot predict the outcome of this proceeding a market-based rates incentive mechanism approved by the including whether the FERC will accept the formula approach.
Maryland PSC. We discuss market-based rates and a proceeding Other market changes are also being considered, including with the Maryland PSC in more detail in the Regulated Gas potential revisions to PJM's capacity market and rate design.
Business-Gas Cost Adjustments section and in Note 6. Such changes will be subject to FERC's review and approval. WVe cannot predict the outcome of these proceedings or the possible Federal Regulation effect on our, or BGE's, financial results at this time.
FERC The FERC has jurisdiction over various aspects of our business. FederalEnergy Legislation including transmission and wholesale electricity sales. Although a While energy legislation was not passed by Congress in 2004, FERC proposed rulemaking regarding implementation of a we expect that some form of energy legislation will be brought standard market design for wholesale electric markets appears to before Congress during the upcoming legislative session. We have halted, FERC has indicated that it continues to have a cannot predict the impact of potential legislation on our strong commitment to customer-focused, competitive wholesale financial results at this time.
power markets, with appropriate flexibility to accommodate regional differences. We believe that FERC's commitment should Weather result in improved competitive markets across various regions. Merchant Energy Business Since 1997, operation of BGE's transmission system has Weather conditions in the different regions of North America been under the authority of PJM, the Regional Transmission influence the financial results of our merchant energy business.
Organization (RTO) for the Mid-Atlantic region, pursuant to Weather conditions can affect the supply of and demand for FERC oversight. As the transmission operator, PJM operates the electricity and fuels. Changes in energy supply and demand may energy markets and conducts day-to-day operations of the bulk impact the price of these energy commodities in both the spot power system. market and the forward market, which may affect our results in In addition to PJM, RTOs exist in other regions of the any given period. Typically, demand for electricity and its price country, such as the Midwest, New York, and New England. In are higher in the summer and the winter, when weather is more addition to operation of the transmission system and responsibility extreme. The demand for and price of natural gas and oil are for transmission system reliability, these RTOs also operate, or higher in the winter. However, all regions of North America plan to operate, energy markets for their region pursuant to typically do not experience extreme weather conditions at the FERC's oversight. Our merchant energy business participates in same time, thus we are not typically exposed to the effects of these regional energy markets. These markets are continuing to extreme weather in all parts of our business at once.
develop, and revisions to market structure are subject to review and approval in proceedings before FERC and other regulatory BGE bodies. We cannot predict the outcome of these proceedings at Weather affects the demand for electricity and gas for our this time. However, changes to the structure of these markets regulated businesses. Very hot summers and very cold winters could have a material effect on our financial results. increase demand. Mild weather reduces demand. Weather affects Recent initiatives at FERC have included a review of its residential sales more than commercial and industrial sales, methodology for the granting of market-based rate authority to which are mostly affected by business needs for electricity and sellers of electricity. FERC has announced new interim tests that gas. The Maryland PSC allows BGE to record a monthly will be used to determine the extent to which companies may adjustment to our regulated gas business revenues to eliminate have market power in certain regions. Where market power is the effect of abnormal weather patterns. We discuss this further found to exist, companies may be required by FERC to in the Regulated Gas Business-Weather Normalization section.
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Other Factors consume more electricity and gas. Conversely, during an A number of other factors significantly influence the level and economic downturn, our customers tend to consume less volatility of prices for energy commodities and related derivative electricity and gas.
products for our merchant energy business. These factors include: Environmental Matters and Legal Proceedings
- seasonal daily and hourly changes in demand, We discuss details of our environmental matters in Note 12 and
- number of market participants, Item 1. Bariness-Environmental Matters section. We discuss details
- extreme peak demands, of our legal proceedings in Note 12. Some of this information is
- available supply resources, about costs that may be material to our financial results.
- transportation and transmission availability and reliability within and benveen regions, Accounting Standards Adopted and Issued
- location of our generating facilities relative to the We discuss recently adopted and issued accounting standards in location of our load-serving obligations, Note 1.
- implementation of new market rules governing operations of regional power pools, Critical Accounting Policies
- procedures used to maintain the integrity of the physical Our discussion and analysis of financial condition and results of electricity system during extreme conditions, operations is based on our consolidated financial statements that
- changes in the nature and extent of federal and state were prepared in accordance with accounting principles generally regulations, and accepted in the United States of America. Management makes
- international demand. estimates and assumptions when preparing financial statements.
These factors can affect energy commodity and derivative These estimates and assumptions affect various matters, prices in different ways and to different degrees. These effects including:
may vary throughout the country as a result of regional
- our reported amounts of revenues and expenses in our differences in: Consolidated Statements of Income,
- weather conditions,
- our reported amounts of assets and liabilities in our
- market liquidity, Consolidated Balance Sheets, and
- capability and reliability of the physical electricity and
- our disclosure of contingent assets and liabilities.
gas systems, These estimates involve judgments with respect to
- local transportation systems, and numerous factors that are difficult to predict and are beyond
- the nature and extent of electricity deregulation. management's control. As a result, actual amounts could Our merchant energy business contracts with rail companies materially differ from these estimates.
to ensure the delivery of coal to our coal-fired generation Management believes the following accounting policies facilities. The timely delivery of coal together with the represent critical accounting policies as defined by the Securities maintenance of appropriate levels of inventory is necessary to and Exchange Commission (SEC). The SEC defines critical allow for continued, reliable generation from these facilities. In accounting policies as those that are both most important to the the second, third, and fourth quarters of 2004, we experienced portrayal of a companys financial condition and results of delays in deliveries from one of the rail companies that supplies operations and require managements most difficult, subjective, coal to our generating facilities. In response, we procured coal or complex judgment, often as a result of the need to make using an alternative delivery method to meet our contractual estimates about the effect of matters that are inherently load obligations. We discuss the impact of these delays on our uncertain and may change in subsequent periods. We discuss our financial results in the Mid-Atlantic Region section. We expect significant accounting policies, including those that do not the majority of the coal that was nor delivered during 2004 will require management to make difficult, subjective, or complex be delivered during 2005. judgments or estimates, in Note 1.
Other factors also impact the demand for electricity and gas in our regulated businesses. These factors include the number of Revenue Recognlton/Mark-to-Market Method of customers and usage per customer during a given period. We use Accounting these terms later in our discussions of regulated electric and gas Our merchant energy business enters into contracts for energy, operations. In those sections, we discuss how these and other other energy-related commodities, and related derivatives. We factors affected electric and gas sales during the periods record merchant energy business revenues using two methods of presented. accounting: accrual accounting and mark-to-market accounting.
The number of customers in a given period is affected by We describe our use of accrual accounting (including hedge new home and apartment construction and by the number of accounting) in more detail in Note 1.
businesses in our service territory. We record revenues using the mark-to-market method of Usage per customer refers to all other items impacting accounting for derivative contracts for which we are not permitted customer sales that cannot be measured separately. These factors to use accrual accounting or hedge accounting. These include the strength of the economy in our service territory. mark-to-market activities include derivative contracts for energy When the economy is healthy and expanding, customers tend to and other energy-related commodities. Under the mark-to-market 27
method of accounting, we record the fair value of these derivatives as we realize cash flows under the contract or when as mark-to-market energy assets and liabilities at the time of observable market data becomes available.
contract execution. We record the changes in mark-to-market
- Credit-spread adjustment-for risk management energy assets and liabilities on a net basis in 'Nonregulated purposes, we compute the value of our mark-to-market revenues" in our Consolidated Statements of Income. energy assets and liabilities using a risk-free discount Mark-to-market energy assets and liabilities consist of a rate. In order to compute fair value for financial combination of energy and energy-related derivative contracts. reporting purposes, we adjust the value of our While some of these contracts represent commodities or mark-to-market energy assets to reflect the credit-instruments for which prices are available from external sources, worthiness of each counterparty based upon either other commodities and certain contracts are not actively traded published credit ratings, or equivalent internal credit and are valued using modeling techniques to determine expected ratings and associated default probability percentages.
future market prices, contract quantities, or both. The market We compute this adjustment by applying a default prices and quantities used to determine fair value reflect probability percentage to our outstanding credit management's best estimate considering various factors. However, exposure, net of collateral, for each counterparty. The future market prices and actual quantities will vary from those level of this adjustment increases as our credit exposure used in recording mark-to-market energy assets and liabilities, to counterparties increases, the maturity terms of our and it is possible that such variations could be material. transactions increase, or the credit ratings of our We record valuation adjustments to reflect uncertainties counterparties deteriorate, and it decreases when our associated with certain estimates inherent in the determination credit exposure to counterparties decreases, the maturity of the fair value of mark-to-market energy assets and liabilities. terms of our transactions decrease, or the credit ratings The effca of these uncertainties is not incorporated in market of our counterpartics improve.
price information or other market-based estimates used to Market prices for energy and energy-related commodities determine fair value of our mark-to-market energy contracts. To vary based upon a number of factors, and changes in market the extent possible, we utilize market-based data together with prices affect both the recorded fair value of our mark-to-market quantitative methods for both measuring the uncertainties for energy contracts and the level of future revenues and costs which we record valuation adjustments and determining the level associated with accrual-basis activities. Changes in the value of of such adjustments and changes in those levels. our mark-to-market energy contracts will affect our earnings in We describe below the main types of valuation adjustments the period of the change, while changes in forward market prices we record and the process for establishing each. Generally, related to accrual-basis revenues and costs will affect our earnings increases in valuation adjustments reduce our earnings, and in future periods to the extent those prices are realized. We decreases in valuation adjustments increase our earnings. cannot predict whether, or to what extent, the factors affecting However, all or a portion of the effect on earnings of changes in market prices may change, but those changes could be material valuation adjustments may be offset by changes in the value of and could affect us either favorably or unfavorably. We discuss the underlying positions. our market risk in more detail in the Market Risk section.
- Close-out adjustment-represents the estimated cost to In October 2002, the EITh reached a consensus on dose out or sell to a third-party open mark-to-market Issue 02-3. This consensus prohibits mark-to-market accounting positions. This valuation adjustment has the effect of for energy-related contracts that do not meet the definition of a valuing 'long" positions (the purchase of a commodity) derivative under Statement of Financial Accounting Standards at the bid price and 'short" positions (the sale of a (SFAS) No. 133, Accounting fir Derivative Instruments and commodity) at the offer price. We compute this Hedging Activities, as amended. As a result, we began to account adjustment using a market-based estimate of the bid/ for all non-derivative contracts on the accrual basis of offer spread for each commodity and option price and accounting effective January 1, 2003 as described in Note 1. The the absolute quantity of our net open positions for each consensus also prohibits recording unrealized gains or losses at year. The level of total close-out valuation adjustments the inception of derivative contracts unless the fair value of each increases as we have larger unhedged positions, bid-offer contract in its entirety is evidenced by quoted market prices or spreads increase, or market information is not available, other current market transactions for contracts with similar and it decreases as we reduce our unhedged positions, terms and counterparties, and it requires gains and losses on bid-offer spreads decrease, or market information derivative energy trading contracts (whether realized or becomes available. To the extent that we are not able to unrealized) to be reported as revenue on a net basis in the obtain observable market information for similar income statement.
contracts, the close-out adjustment is equivalent to the EITF 02-3 affects the timing of recognizing earnings on initial contract margin, thereby resulting in no gain or non-derivative transactions. In general, beginning in 2003 loss at inception. In the absence of observable market earnings on non-derivative transactions subject to EITF 02-3 are information, there is a presumption that the transaction no longer recognized at the inception of the transactions as they price is equal to the market value of the contract, and were under mark-to-market accounting because they are subject therefore we do not recognize a gain or loss at to accrual accounting and are recognized over the term of the inception. We recognize such gains or losses in earnings transaction. As a result, while total earnings over the term of a 28
transaction are the same as they would have been under not recoverable under SFAS No. 144 if the carrying amount mark-to-market accounting, our reported earnings for contracts exceeds the sum of the undiscounted future cash flows expected subject to EITF 02-3 generally match the cash flows from those to result from the use and eventual disposition of the asset.
contracts more closely. Additionally, because we record revenues Therefore, when we believe an impairment condition may have and costs on a gross basis under accrual accounting, our occurred, we are required to estimate the undiscounted future revenues and costs increased, but our earnings have not been cash flows associated with a long-lived asset or group of affected by gross versus net reporting. long-lived assets. This necessarily requires us to estimate The impact of derivative contracts on our revenues and uncertain future cash flows.
costs is affected by many factors, including: In order to estimate an asset's future cash flows, we
- our ability to designate and qualify derivative contracts consider historical cash flows and changes in the market for normal purchase and sale accounting or hedge environment and other factors that may affect future cash flows.
accounting under SFAS No. 133, To the extent applicable, the assumptions we use are consistent
- potential volatility in earnings from derivative contracts with forecasts that we are otherwise required to make (for that serve as economic hedges but do not meet the example, in preparing our other earnings forecasts). If we are accounting requirements to qualify for normal purchase considering alternative courses of action to recover the carrying and sale accounting or hedge accounting, amount of a long-lived asset (such as the potential sale of an
- our ability to enter into new mark-to-market derivative asset), we probability-weight the alternative courses of action to origination transactions, and estimate the cash flows.
- sufficient liquidity and transparency in the energy We use our best estimates in making these evaluations and markets to permit us to record gains at inception of new consider various factors, including forward price curves for derivative contracts because fair value is evidenced by energy, fuel costs, and operating costs. However, actual future quoted market prices, current market transactions, or market prices and project costs could vary from the assumptions other observable market information. used in our estimates, and the impact of such variations could We discuss the impact of mark-to-market accounting on be material.
our financial results in the Results of Operations-Merchant For long-lived assets that can be classified as assets held for Energy Business section. sale under SFAS No. 144, an impairment loss is recognized to the extent their carrying amount exceeds their fair value less Evaluation of Assets for Impairment and Other Than costs to sell.
Temporary Decline In Value If we determine that the undiscounted cash flows from an Long-Lived Assets asset to be held and used are less than the carrying amount of NVC are required to evaluate certain assets that have long lives the asset, or if we have classified an asset as held for sale, we (for example, generating property and equipment and real estate) must estimate fair value to determine the amount of any to determine if they are impaired when certain conditions exist.
impairment loss. The estimation of fair value under SFAS SFAS No. 144, Accounting r the Impairment or Disposalof No. 144, whether in conjunction with an asset to be held and Long-Lived Assets, provides the accounting requirements for used or with an asset held for sale, also involves judgment. We impairments of long-lived assets. We are required to test our consider quoted market prices in active markets to the extent long-lived assets for recoverability whenever events or changes in they are available. In the absence of such information, we may circumstances indicate that their carrying amount may not be consider prices of similar assets, consult with brokers, or employ recoverable. Examples of such events or changes are:
other valuation techniques. Often, we will discount the
- a significant decrease in the market price of a long-lived estimated future cash flows associated with the asset using a asset, single interest rate that is commensurate with the risk involved
- a significant adverse change in the manner an asset is with such an investment or employ an expected present value being used or its physical condition, method that probability-weights a range of possible outcomes.
- an adverse action by a regulator or in the business The use of these methods involves the same inherent uncertainty climate, of future cash flows as discussed above with respect to
- an accumulation of costs significantly in excess of the undiscounted cash flows. Actual future market prices and project amount originally expected for the construction or costs could vary from those used in our estimates, and the acquisition of an asset, impact of such variations could be material.
- a current-period loss combined with a history of losses We are also required to evaluate our equity-method and or the projection of fuiture losses, or cost-method investments (for example, in partnerships that own
- a change in our intent about an asset from an intent to power projects) to determine whether or not they are impaired.
hold to a greater than 50% likelihood that an asset will Accounting Principles Board Opinion (APB) No. 18, The Equhty be sold or disposed of before the end of its previously Method ofAccountingfir Investments in Common Stock, provides estimated useful life.
the accounting requirements for these investments. The standard For long-lived assets that are expected to be held and used, for determining whether an impairment must be recorded under SFAS No. 144 provides that an impairment loss shall only be APB No. 18 is whether the investment has experienced a loss in recognized if the carrying amount of an asset is not recoverable and exceeds its fair value. The carrying amount of an asset is 29
value that is considered an 'other than a temporary" dedine in SFAS No. 143 requires the use of an expected present value value. methodology in measuring asset retirement obligations that The evaluation and measurement of impairments under the involves judgment surrounding the inherent uncertainty of the APB No. 18 standard involves the same uncertainties as probability, amount and timing of payments to settle these described on the previous page for long-lived assets that we own obligations, and the appropriate interest rates to discount future directly and account for in accordance with SFAS No. 144. cash flows. We use our best estimates in identifying and Similarly, the estimates that we make with respect to our equity measuring our asset retirement obligations in accordance with and cost-method investments are subject to variation, and the SFAS No. 143.
impact of such variations could be material. Additionally, if the Our nuclear decommissioning costs represent our largest projects in which we hold these investments recognize an asset retirement obligation. This obligation primarily results from impairment under the provisions of SFAS No. 144, we would the requirement to decommission and decontaminate our record our proportionate share of that impairment loss and nuclear generating facilities in connection with their future would evaluate our investment for an other than temporary retirement. We utilize site-specific decommissioning cost dedine in value under APB No. 18. estimates to determine our nuclear asset retirement obligations.
However, given the magnitude of the amounts involved, Debt and Equity Securities complicated and ever-changing technical and regulatory Our investments in debt and equity securities are subject to requirements, and the very long time horizons involved, the impairment evaluations under SFAS No. 115, Accountingfor actual obligation could vary from the assumptions used in our Certain Investments in Debt and Equity Securities. SFAS No. 115 estimates, and the impact of such variations could be material.
requires us to determine whether a decline in fair value of an investment below the amortized cost basis is other than Significant Events temporary. If we determine that the decline in fair value is In 2004, we recorded the following special items in earnings:
judged to be other than temporary, the cost basis of the Pre- After-Tax Tax investment must be written down to fair value as a new cost basis. We discuss EITF 03-1, The Meaning of Other Than (In millions)
Temporary Impairment and Its Application to Certain Investments. Loss from discontinued operations $(75.6) $(49.1) in the Accounting Standards Issued section of Note 1. Recognition of 2003 synthetic fuel tax credits - 35.9 Workforce reduction costs (9.7) (5.9)
Goodwill Impairment losses and other costs (3.7) (2.2)
Goodwill is the excess of the purchase price of an acquired Net loss on sales of investments and other business over the fair value of the net assets acquired. We assets (1.2) (0.6) account for goodwill and other intangibles under the provisions Total special items $(90.2) $(21.9) of SFAS No. 142, Goodwill and Other Intangible Assets. We do not amortize goodwill and certain other intangible assets. SFAS Loss from Discontinued Operations No. 142 requires us to evaluate goodwill for impairment at least During 2004, we completed the sale of a geothermal facility in annually or more frequently if events and circumstances indicate Hawaii. We recorded a loss of $77.7 million pre-tax, or the business might be impaired. Goodwill is impaired if the $50.4 million after-tax, during the year ended December 31, carrying value of the business exceeds fair value. Annually, we 2004. We reported the after-tax loss as a component of 'Loss estimate the fair value of the businesses we have acquired using from discontinued operations" in our Consolidated Statements techniques similar to those used to estimate future cash flows for of Income. Additionally, prior to sale we recognized earnings long-lived assets as discussed on the previous page, which from the facility of $2.1 million pre-tax, or $1.3 million involves judgment. If the estimated fair value of the business is after-tax as a component of "Loss from discontinued less than its carrying value, an impairment loss is required to be operations." We discuss the loss from discontinued operations in recognized to the extent that the carrying value of goodwill is more detail in Note 2.
greater than its fair value.
Synthetic Fuel Tax Credits Asset Retirement Obligations We have investments in facilities that manufacture solid We incur legal obligations associated with the retirement of synthetic fuel produced from coal as defined under Section 29 certain long-lived assets. SFAS No. 143, Accounting fr Asset of the Internal Revenue Code for which we can claim tax credits Retirement Obligations, provides the accounting for legal on our Federal income tax return until 2007. We recognize the obligations associated with the retirement of long-lived assets. tax benefit of these credits in our Consolidated Statements of We incur such legal obligations as a result of environmental and Income when we believe it is highly probable that the credits other government regulations, contractual agreements, and other will be sustained.
factors. The application of this standard requires significant As of December 31, 2004, we have recognized cumulative judgment due to the large number and diverse nature of the tax benefits associated with Section 29 credits of $201.2 million.
assets in our various businesses and the estimation of future cash In 2004, we recognized $123.2 million in tax benefits for flows required to measure legal obligations associated with the Section 29 credits, including $35.9 million for credits relating to retirement of specific assets. 2003 production. 'at e discuss the synthetic fuel tax credits in more detail in Note 10.
30
Workforce Reduction Costs Results of Operations In the fourth quarter of 2004, we approved a restructuring of In this section, we discuss our earnings and the factors affecting the work forces of the Nine Mile Point and Calvert Cliffs them. WVe begin with a general overview, then separately discuss nuclear generating facilities that was effective in January 2005. earnings for our operating segments. Significant changes in other In connection with this restructuring, approximately 108 income and expense, fixed charges, and income taxes are employees will receive severance and other benefits under our discussed in the aggregate for all segments in the Consolidated existing benefit programs. We accrued the estimated total cost of Nonoperating Income and Expenses section.
this reduction in workforce of $9.7 million pre-tax, or
$5.9 million after-tax, in accordance vith applicable accounting Overview requirements. We expect to realize annual savings in the future Results from reduced labor and benefit costs approximately equal to the 2004 2003 2002 charge recorded in 2004. (In millons. afier-tax)
Merchant energy $439.0 $313.0 $247.2 Impalrment of FinancIal Investment Regulated electric 131.1 107.5 99.3 Our other nonregulated businesses recognized a pre-tax Regulated gas 22.2 43.0 31.1 impairment loss of $3.7 million, or $2.2 million after-tax, Other nonregulated (3.5) 12.2 148.0 during the year ended December 31, 2004 related to an other Net Income Before Cumulative Effecs of than temporary dedine in fair value of certain financial Changes in Accounting Principles 588.8 475.7 525.6 investments. Loss from discontinued operations (49.1) - -
Cumulative effects of changes in Net Loss on Sales of Investments and Other Assets accounting principles - (198.4) -
Our other nonregulated businesses recognized a net pre-tax loss Net Income $539.7 $277.3 $525.6 of $1.2 million, or $0.6 million after-tax, during the year ended Special Itms Included in O.perations:
December 31, 2004 on the sales of non-core assets. We discuss Recognition of 2003 synthetic fuel tax our net loss on sales of investments and other assets in more credits $ 35.9 $ - $ -
detail in Nore 2. Workforce reduction costs (5.9) (1.3) (38.0)
Impairments of real estate, senior-living.
Acquisition and other investments (2,2) (0.4) (1.2)
In June 2004, we completed our purchase of the R E. Ginna Net (loss) gain on sales of investments nuclear facility (Ginna), whidc is located in Ontario, New York and other assets (0.6) 16.4 166.7 Impairments of investment in qualifying from Rochester Gas & Electric Corporation (RG&E). Ginna facilities and domestic power projects - - (9.9) consists of a 495 megawatt reactor that entered service in 1970 Costs associated with exit of BGE Home and is licensed to operate until 2029. We discuss the acquisition merchandise stores - - (6.1) further in Note 15.
Total Special Items $ 27.2 S 14.7 S111.5 Dividend Increase In January 2005, we announced an increase in our quarterly 2004 dividend to $0.335 per share on our common stock. This is Our total net income for 2004 increased $262.4 million, or equivalent to an annual rate of $1.34 per share. Previously, our $1.46 per share, compared to the same period of 2003 mostly quarterly dividend on our common stock was $0.285 per share, because of the following:
equivalent to an annual rate of $1.14 per share.
- In 2003, we recorded a $266.1 million after-tax, or
$1.60 per share, loss for the cumulative effect of adopting EITF 02-3. This was partially offset by a
$67.7 million after-tax, or $0.41 per share, gain for the cumulative effect of adopting Statement of Financial Accounting Standards (SFAS) No. 143, Accountingfor Asse Retirement Obligations. These items had a combined negative impact during 2003.
- Our merchant energy business had higher earnings of
$78.4 million at our South Carolina synfuel facility primarily due to the recognition of $35.9 million in tax credits associated with 2003 production and tax credits associated with 2004 production.
- We had higher earnings from our regulated electric business mostly because of the absence of $19.4 million of after-tax incremental operations and maintenance expenses due to distribution service restoration efforts associated with Hurricane Isabel in 2003.
31
- We had higher earnings from our nuclear generating
- We had higher fixed charges of $58.7 million due to assets due to the June 2004 acquisition of Ginna, which lower capitalized interest of $30.2 million and contributed $28.1 million after-tax, and higher $28.5 million primarily related to a higher level of debt generation at our Galvert Cliffs nuclear power plant, outstanding as a result of refinancing our High Desert partially offset by lower generation by and lower power facility.
prices for the output of our Nine Mile Point facility in
- Our results reflect the impact of the shift to accrual 2004 compared to 2003. accounting under EITF 02-3. Specifically, the absence of
- We had higher earnings from our merchant energy 2002 mark-to-market gains for contracts accounted for business mostly due to the realization of wholesale on an accrual basis in 2003 and the timing difference in contracts originated in prior periods, portfolio the recognition of earnings for certain economic hedges, management, and favorable settlements at our retail which we discuss further in the Competitive Supply-electric operation of $16.9 million pre-tax. Mark-to-Market Revenued section, were only partially
- We had higher earnings due to lower pre-tax losses of offset by the 2003 recognition of accrual earnings on
$47.7 million associated with economic hedges that do transactions entered into in prior periods.
not qualify for cash-flow hedge accounting treatment.
- Our regulated electric business incurred incremental
- We had higher earnings of $20.9 million after-tax in distribution service restoration expenses of $19.4 million 2004 due to a full year of operations at the High Desert after-tax associated with Hurricane Isabel.
facility. These decreases were partially offset by the following:
These increases were partially offset by the following-
- We had higher earnings from wholesale competitive
- We recorded a $49.1 million after-tax, or $0.28 per supply activities including effective portfolio share, loss from discontinued operations. management, partially offset by lower mark-to-market
- We had higher Sarbanes-Oxley 404 implementation origination in 2003.
costs of approximately $15 million pre-tax, higher
- We had $39.5 million of higher earnings from our enterprise information systems expenditures of regulated business, excluding the impacts of Hurricane approximately $8 million pre-tax, and higher Isabel.
compensation, benefit, and other inflationary cost
- We had higher earnings from favorable generating plant increases. operational performance. Specifically, our High Desert
- We had lower earnings from our regulated gas business facility commenced operations in April 2003 mostly because of $13.6 million after-tax of higher contributing $39.1 million after-tax, and Calvert Cliffs operations and maintenance expenses in 2004 and the completed a steam generator replacement in April 2003, absence of a $4.7 million after-tax market-based rate gas 58 fewer days than a similar outage that was completed recovery, which had a favorable effect in 2003. in June 2002.
- We recognized a gain of $16.4 million after-tax related
- We had $36.7 million after-tax of higher workforce to non-core asset sales in 2003 that had a favorable reduction costs in 2002 that had a negative impact in impact in that period. the period.
Earnings per share was impacted by additional dilution
- We realized cost reductions due to productivity resulting from the issuance of 6.0 million shares of common initiatives.
stock on July 1, 2004.
- We had higher earnings from a full year at our retail electric operation, which contributed $20.3 million, and 2003 from the acquisition of our retail gas operation, which Our total net income for 2003 decreased $248.3 million, or contributed $4.1 million.
$1.54 per share, compared to 2002 mostly because of the
- Our other nonregulated business recognized a gain of following: $16.4 million after-tax, or $0.10 per share, in 2003
- We recorded a $266.1 million after-tax, or $1.60 per related to non-core asset sales.
share, charge for the cumulative effect of adopting
- We had higher earnings from our other nonregulated EITF 02-3. This was partially offset by a $67.7 million businesses primarily related to improved operations of after-tax, or $0.41 per share, gain for the cumulative our international portfolio of $7.0 million after-tax.
effect of adopting SFAS No. 143.
- We had $6.1 million after-tax of costs associated with
- We recognized a $163.3 million after-tax, or $1.00 per our exit of BGE Home merchandise stores in 2002 that share, gain on the sale of our investment in Orion had a negative impact in that period.
Power Holdings, Inc. (Orion) in 2002 that had a
- We recognized impairments of certain investments in positive impact in that period. We discuss the sale of qualifying facilities, real estate, and other investments in Orion in more detail in Note 2. 2002 that had a negative impact in that period.
32
Merchant Energy Business EITF 02-3 affects the timing of recognizing earnings on Background non-derivative transactions. Earnings on new non-derivative Our merchant energy business is a competitive provider of transactions subject to EITF 02-3 are no longer recognized at energy solutions for various customers. We discuss the impact of the inception of the transactions as they were under deregulation on our merchant energy business in Item 1. mark-to-market accounting because they are subject to accrual Business-Competition section. accounting and are recognized over the term of the transaction.
We record merchant energy revenues and expenses in our Additionally, we expect lower earnings volatility for this financial results in different periods depending upon which portion of our business because unrealized changes in the fair portion of our business they affect. We discuss our revenue value of non-derivative load-serving contracts will no longer be recognition policies in the CriticalAccountingPolicies section and recorded as revenue at the time of the change as they were in Note 1. We summarize our policies as follows: under mark-to-market accounting.
- We record revenues as they are earned and fuel and purchased energy expenses as they are incurred for Results contracts and activities subject to accrual accounting, 2004 2003 2002 including certain load-serving activities. (In millions)
- Prior to the settlement of the forecasted transaction Revenues $10.389.9 $ 7,632.9 $ 2,781.3 being hedged, we record changes in the fair value of Fuel and purchased energy contracts designated as cash-flow hedges in other expenses (8,129.3) (5,706.1) (1,208.3) comprehensive income to the extent that the hedges are Operating expenses (1,178.4) (935.9) (759.8) effective. We record the effective portion of the changes Workforce reduction costs (9.7) (1.2) (26.5)
Impairment losses and other costs - - (14.4) in fair value of hedges in earnings in the period the Depreciation and amortization (248.0) (229.5) (242.8) settlement of the hedged transaction occurs. We record Accretion of asset retirement the ineffective portion of the changes in fair value of obligations (53.2) (42.7) hedges, if any, in earnings in the period in which the Taxes other than income taxes (91.5) (89.2) (69.7) change occurs. Net loss on sales of assets - - (3.7)
- We record changes in the fair value of contracts that are Income from Operations $ 679.8 $ 628.3 S 456.1 subject to mark-to-market accounting in revenues on a Income from continuing net basis in the period in which the change occurs. operations before cumulative Mark-to-market accounting requires us to make estimates effects of changes in and assumptions using judgment in determining the fair value of accounting principles (afier-tax) $ 439.0 S 313.0 S 247.2 certain contracts and in recording revenues from those contracts. Loss from discontinued We discuss the effects of mark-to-market accounting on our operations (afier-tax) (49.1) - -
revenues in the Competitive Suppl-Mark-to-Market Revenues Cumulative effects of changes in section. We discuss mark-to-market accounting and the accounting principles (after-tax) - (198.4) -
accounting policies for the merchant energy business further in Net Income $ 389.9 $ 114.6 $ 247.2 the CriticalAccounting Policies section and in Note 1. Special Items Inclded in Operaton In the first quarter of 2003, we adopted EITF 02-3, which (after-tax) required non-derivative contracts to be accounted for on the Recognition of 2003 synthetic accrual basis and recorded in our Consolidated Statements of fuel tax credits $ 35.9 $ - S -
Income gross rather than net. The primary contracts affected Workforce reduction costs (5.9) (0.7) (16.0) were our full requirements load-serving contracts and Impairment of investments in unit-contingent power purchase contracts. The majority of these qualifying facilities and domestic power projects - - (9.9) contracts were in Texas and New England and were entered into Net loss on sales of assets - - (2.4) prior to our shift to accrual accounting earlier in 2002. We discuss our shift to accrual accounting during 2002 in more Total Special Items $ 30.0 S (0.7) S (28.3) derail in the Molesale Accrual Activities section. After the Above amounts include intercompany transactions eliminated in our re-designation of existing contracts to non-trading, we record ConsolidatedFinancialStatements. Note 3 provides a reconciliation revenues and expenses on a gross basis, but this does not have a of operating results by segment to our ConsolidatedFinancial material impact on earnings because the resulting increase in Statements. Certain prior-yearamounts have been reclassifiedto revenues is accompanied by a similar increase in fuel and conform with the currentyearspresentation.
purchased energy expenses.
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Revenues and Fuel and PurchasedEnergy Eipenses WVe provide a summary of our revenues, fuel and purchased Our merchant energy business manages the revenues we realize energy expenses, and gross margin as follows:
from the sale of energy to our customers and our costs of 2004 2003 2002 procuring fuel and energy. The difference between revenues and fuel and purchased energy expenses is the gross margin of our (Dollar amounu in millon) merchant energy business, and this measure is management's Revenues:
primary tool for assessing the profitability of our merchant Mid-Atlantic Region $ 1,925.6 $ 1,696.2 S 1,415.1 energy business. Accordingly, we believe it is appropriate to Plants with discuss the operating results of our merchant energy business by Power analyzing the changes in gross margin between periods. In Purchase managing our portfolio, we occasionally terminate, restructure, Agreements 756.9 620.0 456.4 or acquire contracts. Such transactions are within the normal Competitive course of managing our portfolio and may materially impact the Supply timing of our recognition of revenues, fuel and purchased energy Retail 4,280.0 2,567.7 312.7 expenses, and cash flows. Wholesale 3353.8 2,703.9 540.7 We analyze our merchant energy gross margin in the Other 73.6 45.1 56.4 following categories because of the risk profile of each category, Total $10389.9 S7,632.9 $ 2.781.3 differences in the revenue sources, and the nature of fuel and Fuel and purchased energy expenses. With the exception of a portion of purchased our competitive supply activities that we are required to account energy expenses:
for using the mark-to-market method of accounting, all of these Mid-Atlantic activities are accounted for on an accrual basis. Region $ (946.9) $ (711.6) $ (551.2)
- Mid-Atlantic Region-our fossil, nudear, and Plants with rower hydroelectric generating facilities and load-serving Purchase activities in the PJM Interconnection (PJM) region for Agreements (57.6) (51.9) (40.0) which the output is primarily used to serve BGE. This Competitive also indudes active portfolio management of the Supply generating assets and other physical and financial Retail (4,011.4) (2,389.5) (273.2) contractual arrangements, as well as other PJM Wholesale (3,113.4) (2,553.1) (343.9) competitive supply activities. Other - - -
- Plants with Power Purchase Agreements-our generating Total $ (8,129.3) $(5,706.1) $(1,208.3) facilities outside the Mid-Atlantic Region with long-term %of %of % of power purchase agreements, induding the Nine Mile Point, Ginna, Oleander, University Park, and High Gross margin: Total Total Total Mid-Adantic Desert facilities. Region $ 978.7 43% $ 984.6 51% $ 863.9 55%
- Wholesale Competitive Supply-our marketing and risk Plants with management operation that provides energy products Power and services outside the Mid-Atlantic Region primarily Purchase to distribution utilities, power generators, and other Agreements 699.3 31 568.1 29 416.4 26 wholesale customers. Competitive
- Retail Competitive Supply-our operation that provides Supply electric and gas energy products and services to Retail 268.6 12 178.2 9 39.5 3 commercial and industrial customers.
Wholesale 240.4 11 150.8 8 196.8 13 Other 73.6 3 45.1 3 56.4 3
- Other-our investments in qualifying facilities and domestic power projects and our operations and Total $ 2,260.6 100% $ 1,926.8 100% $ 1,573.0 100%
maintenance consulting services. Certainprior-year amounts harv been rrceLwtfied to conform with the current years presentation.
Mid-Atlantic Region 2004 2003 2002 (In millions)
Revenucs $1,925.6 $1,696.2 $1,415.1 Fuel and purchased energy expenses (946.9) (711.6) (551.2)
Gross margin $ 978.7 $ 984.6 $ 863.9 34
The decrease in Mid-Atlantic Region gross margin in 2004
- higher gross margin of $18.7 million from the Oleander compared to 2003 is primarily due to lower fossil plant generating facility that contributed a full year of gross availability resulting in lower margin of $17.0 million and margin during 2003 compared to six months of higher coal costs primarily due to purchasing coal from operations during 2002.
alternative suppliers in 2004 at higher prices than in 2003 as a result of delays in deliveries as discussed in the Business Competitive Supply Environment-OtherFactors section. These decreases were Retail partially offset by an increase in margin of $7.1 million related to new load-scrving obligations, offset in part by lower volumes 2004 2003 2002 served to BGE resulting from small commercial customers (In millions) leaving BGE's standard offer service due to the end of fixed- Accrual revenues $ 4,281.0 $ 2,567.7 S 312.7 price service in June 2004. Mark-to-market revenues (1.0) - -
The increase in Mid-Atlantic Region gross margin in 2003 Fuel and purchased energy expenses (4,011.4) (2,389.5) (273.2) compared to 2002 is primarily due to: Gross margin $ 268.6 $ 178.2 S 39.5
- higher margins of approximately $85 million from our The increase in gross margin from our retail competitive supply owned generation in excess of that used to serve BGE's activities in 2004 compared to 2003 is primarily due to higher standard offer service, including our active portfolio electric gross margin of $66.1 million mostly due to:
management of these generating assets and associated
- serving approximately 16 million more megawatt hours physical and financial arrangements, and partially offset by lower realized margins due to
- a gain on the assumption of the Allegheny Energy increased wholesale power costs in 2004 compared to Supply Company, LLC. load-serving contract for the 2003, remaining 10% of the BGE standard offer service load.
- a bankruptcy settlement from PG&E of $10.3 million, and a favorable settlement of a pre-acquisition liability Plants with Power PurchaseAgreements of $6.6 million also related to a bankruptcy proceeding, 2004 2003 2002 and
- lower contract amortization, which reduces margin, of (In millions)
$9.2 million relating to the fair value of contracts at Revenues $756.9 $620.0 $456.4 Fuel and purchased energy expenses (57.6) (51.9) (40.0) acquisition.
In addition, we had higher gas gross margin contribution of Gross margin $6993 $568.1 $416.4 $17.1 million from Blackhawk Energy Services and Kaztex The increase in gross margin from our Plants with Power Energy Management, which were acquired in October 2003. We Purchase Agreements in 2004 compared to 2003 is primarily discuss our acquisitions in more detail in Note 15.
due to: The incaease in gross margin from our retail competitive
- gross margin of $112.4 million from Ginna, which was supply activities in 2003 compared to 2002 is due to:
acquired in June 2004. The increase in gross margin
- a full year of electric gross margin contribution of includes higher revenues of $119.1. million. We discuss $115.9 million. The increase in electric gross margin this acquisition in more derail in Note 14, and includes higher revenues of $1,170.2 million. Our retail
- higher gross margin of $45.9 million from the High electric operation was acquired in September 2002, and Desert facility that contributed a full year of gross
- a full year of gas gross margin contribution of margin in 2004 compared to eight months in 2003. $22.8 million. The increase in gas gross margin includes These increases in gross margin were partially offset by higher revenues of $1,084.8 million. Our retail gas lower gross margin of $21.0 million at our Nine Mile Point operation was acquired in December 2002.
facility primarily due to lower revenues from reduced contract prices for the output in 2004 compared to 2003 and lower Wholesale generation. 2004 2003 2002 The increase in gross margin from our Plants with Power (In millions)
Purchase Agreements in 2003 compared to 2002 is primarily Accrual revenues $ 3,253.7 S 2,667.7 S 310.7 due to: Fuel and purchased energy expenses (3,113.4) (2.553.1) (343.9)
- gross margin of $105.5 million from the High Desert Wholesale accrual activities 1403 114.6 (33.2) facility, which commenced operations in the second Mark-to-markct revenues 100.1 36.2 230.0 quarter of 2003. The increase in gross margin includes Gross margin $ 240.4 S 150.8 S 196.8 higher revenues of $11.3 million,
- higher gross margin of $22.6 million from Nine Mile Point primarily due to fewer forced outage days in 2003 compared to 2002, and 35
In January 2003, we adopted EITF 02-3 that changed the The increase in revenues, fuel and purchased energy accounting for certain energy contracts. EITF 02-3 prohibits the expenses, and gross margin from our wholesale accrual activities use of mark-to-market accounting for any energy-related in 2003 compared to 2002 is primarily due to the impact of the contracts that are not derivatives. Any non-derivative contracts adoption of EITF 02-3 as discussed above. While it is not must be accounted for on the accrual basis and recorded in the practicable to determine precisely the impact of EITF 02-3 on income statement gross rather than net upon applicationof revenues and gross margin, accrual revenues for 2003 include EITF 02-3. This change applied immediately to new contracts approximately $1.4 billion from load-serving contracts that executed after October 25, 2002 and applied to existing existed at January 1, 2003 (the date EITE 02-3 was adopted) non-derivative energy-related contracts beginning January 1, which had been accounted for on a mark-to-market basis in 2003. During 2002, the majority of our wholesale results were 2002.
on the mark-to-market method of accounting. In addition, our wholesale accrual revenues and fuel and The portion of competitive supply revenues, fuel and purchased energy expenses were impacted in 2002 by the purchased energy expenses, and gross margin derived from re-designation of our Texas and New England load-serving accrual and mark-to-market contracts changed significantly due activities to accrual.
to the adoption of EITF 02-3. Effective January 1, 2003, we In February 2002, we began to manage our Texas began to account for all non-derivative contracts on the accrual load-serving activities as a physical delivery business separate basis, whereas we had accounted for these contracts on the from our trading activities and re-designated these activities as mark-to-market basis in 2002. We also began to recognize non-trading. After the change in designation, the results of our origination gains only for derivative contracts for which we have Texas load-serving activities are included in "Nonregulated observable market prices. These changes increased accrual revenues" on a gross basis as power is delivered to our customers competitive supply revenues, fuel and purchased energy expenses, and "Fuel and purchased energy expenses" as costs are incurred.
and gross margin and deaeased mark-to-market competitive Prior to the re-designation, the results of these activities were supply revenues and gross margin in 2003 as compared to 2002. reported on a net basis as part of mark-to-market revenues EITF 02-3 affected a large number of competitive supply included in 'Nonregulated revenues." Mark-to-market revenues contracts, and we cannot quantify its total impact precisely for the Texas trading activities were a net loss of $1.2 million for because we cannot recast our 2002 results to reflect accrual the portion of 2002 prior to designation as non-trading.
accounting, nor did we maintain separate mark-to-market Since future power sales revenues and costs from these accounting records for accrual contracts beginning in 2003. activities are reflected in our Consolidated Statements of Income However, the larger portion of our competitive supply activities as part of "Nonregulated revenues" when power is delivered and that became subject to accrual accounting under EITF 02-3 "Fuel and purchased energy expenses" when the costs are resulted in an increase in total competitive supply revenues and incurred, this re-designation generally delays the recognition of fuel and purchased energy expenses, but a decrease in total earnings from these activities compared to what we would have competitive supply gross margin in 2003 compared to 2002. recognized under mark-to-market accounting. The change in We analyze our wholesale accrual and mark-to-market designation of our Texas load-serving activities did not impact competitive supply activities separately below. our cash flows.
In addition, our New England load-serving activities consist Wholsale Accrual Activities primarily of contracts to serve the full energy and capacity The increase in gross margin from our wholesale accrual requirements of retail customers and electric distribution utilities activities in 2004 compared to 2003 is primarily due to and associated power purchase agreements to supply our approximately $50 million in the New England region due to customers' requirements. We manage these activities primarily to higher realized contract margins in 2004 compared to 2003 and assure profitable delivery of customers' energy requirements higher volumes served. This increase was partially offset by rather than as a traditional proprietary trading activity where higher transportation costs for our gas trading portfolio of profits or losses result from taking directional positions on approximately $16 million. The transportation costs associated market price changes. Therefore. we use accrual accounting for with this portfolio are accounted for on an accrual basis, while New England load-serving transactions and associated power our gas trading portfolio is recorded as mark-to-market. In purchase agreements entered into since the second quarter of addition, we incurred higher operating costs of $5.0 million 2002.
related to our South Carolina synthetic fuel facility.
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Because applicable accounting rules significantly limited the Origination gains arise primarily from contracts that our circumstances under which contracts previously designated as a wholesale marketing and risk management operation structures trading activity could be re-designated as non-trading, prior to to meet the risk management needs of our customers.
EITF 02-3, we were required to continue to include contracts Transactions that result in origination gains may be unique and entered into before the second quarter of 2002 in our provide the potential for individually significant revenues and mark-to-market accounting portfolio. However, under gains from a single transaction.
EITF 02-3, on January 1, 2003, we removed these contracts Origination gains represent the initial fair value recognized from our "Mark-to-market energy assets and liabilities" and on these structured transactions. The recognition of origination began to account for these contracts under the accrual method gains is dependent on the existence of observable market data of accounting. that validates the initial fair value of the contract. Origination gains arose from 13 transactions completed in 2004 and 14 Mark-to-Market Revenues transactions completed in 2003, of which no transaction Mark-to-market revenues include net gains and losses from individually contributed in excess of $10 million pre-tax.
origination and risk management activities for which we use the As noted on the previous page, the recognition of mark-to-market method of accounting. We discuss these origination gains is dependent on sufficient observable market activities and the mark-to-market method of accounting in more data. Liquidity and market conditions impact our ability to detail in the CriticalAccounting Policies section and in Note 1. identify sufficient, objective market-price information to permit We also discuss the implications of EITF 02-3 on the recognition of origination gains. As a result, while our strategy mark-to-market method of accounting in the CriticalAccounting and competitive position provide the opportunity to continue to Policies section. originate such transactions, the level of origination revenue we As a result of the nature of our operations and the use of are able to recognize may vary from year to year as a result of mark-to-market accounting for certain activities, mark-to-market the number, size, and market-price transparency of the revenues and earnings will fluctuate. We cannot predict these individual transactions executed in any period.
fluctuations, but the impact on our revenues and earnings could Risk management revenues represent both realized and be material. We discuss our market risk in more detail in the unrealized gains and losses from changes in the value of our Market Risk section. The primary factors that cause fluctuations entire portfolio, including the recognition of gains associated in our mark-to-market revenues and earnings are: with decreases in the close-out adjustment when we are able to
- the number, size, and profitability of new transactions obtain sufficient market price information. We discuss the including terminations or restructuring of existing changes in mark-to-market revenues below. We show the contracts, relationship between our revenues and the change in our net
- the number and size of our open derivative positions, mark-to-market energy asset later in this section.
and Our mark-to-market revenues were and continue to be
- changes in the level and volatility of forward commodity affected by a decrease in the portion of our activities that is prices and interest rates. subject to mark-to-market accounting. As previously discussed in Mark-to-market revenues were as follows: the Whoksale AccrualActivities section, we re-designated our Texas load-serving activities as accrual during 2002, and we 2004 2003 2002 began to account for new non-derivative origination transactions (In millions) on the accrual basis rather than under mark-to-market Unrealized revenues accounting. Beginning January 1, 2003, under EITF 02-3, we Origination gains $ 19.7 S 62.3 $160.4 no longer record existing non-derivative contracts at fair value.
Risk management Unrealized changes in fair value 79.4 (26.1) 58.8 Further, effective July 1, 2002, to the extent that we are not able Changes in valuation techniques - - 10.8 to observe quoted market prices or other current market Redassification of setded contracts transactions for contract values determined using models, we to realized (85.4) (123.5) (45.4) record a valuation adjustment to result in zero gain or loss at Total risk management (6.0) (149.6) 24.2 inception. W~e remove the valuation adjustment in determining Total unrealized revenues 13.7 (87.3) 184.6 fair value when we obtain current market information for Realized revenues 85.4 123.5 45.4 contracts with similar terms and counterparties.
Total mark-to-market revenues $ 99.1 $ 36.2 $230.0 Mark-to-market revenues increased $62.9 million in 2004
- Total unrealized revenues is the sum of origination transactions compared to 2003 mostly because of the impact of lower and total risk management. mark-to-market losses on economic hedges that do not qualify for hedge accounting treatment as discussed in more detail on the next page and lower losses from risk management activities primarily due to favorable changes in regional power prices, and price volatility. These increases were partially offset by a lower level of origination gains in 2004 compared to 2003. The lower level of origination gains is primarily due to higher individually significant gains on contracts in 2003 that had a positive impact in that period.
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Mark-to-market revenues decreased $193.8 million in 2003 The following are the primary sources of the change in net compared to 2002 mostly because of lower revenues from mark-to-market energy asset during 2004 and 2003:
origination transactions, net losses from risk management activities compared to net gains in the prior year, and the 20(M4 2003 reclassification of revenues from settled contracts to realized (In millions) revenues. The lower level of origination transactions primarily Fair value beginning of year $18.8 S516.6 Changes in fair value recorded as reflects the continuing reduction of the portion of our activities revenues subject to mark-to-market accounting. The decrease in risk Origination gains S 19.7 $ 62.3 management revenues is primarily due to mark-to-market Unrealized changes in fair value 79.4 (26.1) revenue associated with the restructuring of our High Desert Changes in valuation techniques contract with the CDWR that had a positive impact in 2002. Reclassification of settled unfavorable changes in regional power prices, price volatility, and contracts to realized (85.4) (123.5) the impact of mark-to-marker losses on economic hedges that Total changes in fair value recorded did not qualify for hedge accounting treatment as discussed in as revenues 13.7 (87.3) more detail below. Cumulative effect impact of EITF With the implementation of EITF 02-3 in the first quarter 02-3 (379.4) of 2003, all of our load-serving contracts were converted to Contracts designated as normal accrual accounting. However, several economically effective purchases/sales and hedges upon hedges on these positions did not qualify for accrual accounting implcmentation of EITF 02-3 (58.2)
Contract exchange (68.9) treatment under SFAS No. 133 and remained in the Changes in value of exchange-listed mark-to-market portfolio. In 2003, increasing forward prices futures and options (15.8) (8.4) shifted value between accrual load-serving positions and Net change in premiums on associated mark-to-market hedges producing a timing difference options 29.4 99.3 in the recognition of earnings on related transactions. As a Other changes in hir value 6.3 5.1 result, we recorded $0.3 million of pre-tax gains in 2004 and Fair value at end of year S 52.4 S 18.8
$47.4 million of pre-tax losses on the mark-to-market hedges during 2003. This mark-to-market loss will be offset as we Changes in the net mark-to-market energy asset that realize the related accrual load-serving positions in cash. affected revenues were as follows:
- Origination gains represent the initial unrealized fair value at the time these contracts are executed to the Mark-to-Market Energy Assets and Liabilities Our mark-to-market energy assets and liabilities are comprised of extent permitted by applicable accounting rules.
- Unrealized changes in fair value represent unrealized derivative contracts. While some of our mark-to-market contracts represent commodities or instruments for which prices are changes in commodity prices, the volatility of options available from external sources, other commodities and certain on commodities, the time value of options, and other contracts are not actively traded and are valued using other valuation adjustments.
pricing sources and modeling techniques to determine expected
- Changes in valuation techniques represent improvements future market prices, contract quantities, or both. We discuss our in estimation techniques, including modeling and other modeling techniques later in this section. statistical enhancements used to value our portfolio to Mark-to-market energy assets and liabilities consisted of the reflect more accurately the economic value of our contracts.
following:
- Reclassification of settled contracts to realized represents At Dec mbe 31, 2004 2003 the portion of previously unrealized amounts settled (In millions) during the period and recorded as realized revenues.
Current Assets $567.3 $504.8 The net mark-to-market energy asset also changed due to Noncurrent Assets 359.8 265.8 the following items recorded in accounts other than revenue:
Total Assets 927.1 770.6
- The cumulative effect impact of EITF 02-3 represents the non-derivative portion of the net asset that was Current Liabilities 559.7 490.4 removed from our Consolidated Balance Sheets as a Noncurrent Liabilities 315.0 261.4 cumulative effect of change in accounting principle Total Liabilities 874.7 751.8 effective January 1, 2003 as required by EITF 02-3.
Net mark-to-market energy asset $ 52.4 $ 18.8 Certainprior-yearamounts have been reclassifiedto conform with the current years presentation.
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- Contracts designated as normal purchases/sales and
- Changes in value of exchange-listed futures and options hedges upon implementation of EITF 02-3 represents are adjustments to remove unrealized revenue from the portion of the net asset reclassified to 'Other assets exchange-traded contracts that are included in risk or liabilities" under the normal purchases/normal sales management revenues. The fair value of these contracts provisions of SFAS No. 133 or "Risk management assets is recorded in "Accounts receivable" rather than or liabilities" under the cash-flow hedge provisions of "Mark-to-market energy assets" in our Consolidated SFAS No. 133 in connection with the implementation Balance Sheets because these amounts are settled of EITF 02-3 effective January 1, 2003. through our margin account with a third-party broker.
- Contract exchange represents the fair value of a contract
- Net changes in premiums on options reflects the previously included in "Mark-to-market energy assets accounting for premiums on options purchased as an that we terminated in a nonmonetary exchange with a increase in the net mark-to-market energy asset and counterparty. At that time, we also terminated a hedge premiums on options sold as a decrease in the net contract with the same counterparty that was recorded mark-to-market energy asset.
in 'Risk management liabilities." In exchange, we entered into a new cash-flow hedge transaction with the counterparty that we recorded at an amount equal to the fair value of the terminated contracts.
The settlement terms of our net mark-to-market energy asset and sources of fair value as of December 31, 2004 are as follows:
Settlement Term 2005 2006 2007 . 2008 2009 2010 Thereafter Fair Value (In millions)
Prices provided by external sources (I) $17.2 $29.5 $ 123.0 $ 61.6 $ - $ - $ 231.3 Prices based on models (9.6) (8.3) (101.7) (54.6) (1.5) (1.8) (1.4) (178.9)
Total net mark-to-market energy asset $ 7.6 $21.2 $ 21.3 $ 7.0 $(1.5) $(l.8) $(1.4) $ 52.4 (1) Includes contracts actively quoted and contracts valued from other external sources.
We manage our mark-to-market risk on a portfolio basis The amounts for which fair value is determined using based upon the delivery period of our contracts and the prices provided by external sources represent the portion of individual components of the risks within each contract. forward, swap, and option contracts for which price quotations Accordingly, we record and manage the energy purchase and sale are available through brokers or over-the-counter transactions.
obligations under our contracts in separate components based The term for which such price information is available varies by upon the commodity (e.g., electricity or gas), the product (e.g., commodity, region, and product. The fair values included in this electricity for delivery during peak or off-peak hours), the category are the following portions of our contracts:
delivery location (e.g., by region), the risk profile (e.g., forward
- forward purchases and sales of electricity during peak or option), and the delivery period (e.g., by month and year). and off-peak hours for delivery terms primarily through Consistent with our risk management practices, we have 2006, but up to 2008, depending upon the region, presented the information in the table above based upon the
- options for the purchase and sale of electricity during ability to obtain reliable prices for components of the risks in peak hours for delivery terms through 2005, depending our contracts from external sources rather than on a upon the region, contract-by-contract basis. Thus, the portion of long-term
- forward purchases and sales of electric capacity for contracts that is valued using external price sources is presented delivery terms through 2006, under the caption 'prices provided by external sources." This is
- forward purchases and sales of natural gas, coal and oil consistent with how we manage our risk, and we believe it for delivery terms through 2008, and provides the best indication of the basis for the valuation of our
- options for the purchase and sale of natural gas, coal portfolio. Since we manage our risk on a portfolio basis rather and oil for delivery terms through 2006.
than contract-by-contract, it is not practicable to determine The remainder of the net mark-to-market energy asset is separately the portion of long-term contracts that is included in valued using models. The portion of contracts for which such each valuation category. We describe the commodities, products, techniques are used includes standard products for which and delivery periods included in each valuation category in detail external prices are not available and customized products that are below. valued using modeling techniques to determine expected future market prices, contract quantities, or both.
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Modeling techniques include estimating the present value of Management uses its best estimates to determine the fair cash flows based upon underlying contractual terms and value of commodity and derivative contracts it holds and sells.
incorporate, where appropriate, option pricing models and These estimates consider various factors including closing statistical and simulation procedures. Inputs to the models exchange and over-the-counter price quotations, time value, include: volatility factors, and credit exposure. However, future market
- observable market prices, prices and actual quantities will vary from those used in
- estimated market prices in the absence of quoted market recording mark-to-market energy assets and liabilities, and it is prices, possible that such variations could be material.
- the risk-free market discount rate,
- volatility factors, Other
- estimated correlation of energy commodity prices, and 2004 2003 2002
- expected generation profiles of specific regions. (In millions)
Additionally, we incorporate counterparry-specific credit Revenues $73.6 $45.1 $56.4 quality and factors for market price and volatility uncertainty and other risks in our valuation. The inputs and factors used to Our merchant energy business holds up to a 50% voting interest determine fair value reflect management's best estimates. in 24 operating domestic energy projects that consist of electric The electricity, fuel, and other energy contracts we hold generation, fuel processing, or fuel handling facilities. Of these have varying terms to maturity, ranging from contracts for 24 projects, 17 are "qualifying facilities" that receive certain delivery the next hour to contracts with terms of ten years or exemptions and pricing under the Public Utility Regulatory more. Because an active, liquid electricity futures market Policy Act of 1978 based on the facilities' energy source or the comparablc to that for other commodities has not developed, the use of a cogeneration process. Earnings from our investments majority of contracts used in the wholesale marketing and risk were $18.0 million in 2004, $2.1 million in 2003, and management operation arc direct contracts between market $9.1 million in 2002.
participants and arc not cxchange-traded or financially settling The increase in revenues in 2004 compared to 2003 is contracts that can be readily liquidated in their entirety through primarily due to higher equity in earnings related to our an exchange or other market mechanism. Consequently, we and minority investment in a facility that produces synthetic fuel other market participants generally realize the value of these from coal. This increase included $13.1 million of revenues contracts as cash flows become due or payable under the terms related to an increased incentive fee and a deferred contingent of the contracts rather than through selling or liquidating the transaction fee.
contracts themselves. The decrease in revenues in 2003 compared to 2002 was Consistent with our risk management practices, the due to lower revenues from our California projects because we amounts shown in the table on the previous page as being reversed certain credit reserves that totaled $9.1 million during valued using prices from external sources include the portion of the first quarter of 2002, as we began receiving payments from long-term contracts for which we can obtain reliable prices from the California utilities, which had a positive impact in 2002, external sources. The remaining portions of these long-term partially offset by a geothermal project generating at a higher contracts are shown in the table as being valued using models. capacity in 2003.
In order to realize the entire value of a long-term contract in a At December 31, 2004, our investment in qualifying single transaction, we would need to sell or assign the entire facilities and domestic power projects consisted of the following:
contract. If we were to sell or assign any of our long-term contracts in their entirety, we may not realize the entire value Book Value at December 31, 2004 2003 reflected in the table. However, based upon the nature of the (In millons) wholesale marketing and risk management operation, we expect Project Type to realize the value of these contracts, as well as any contracts we -Coal $128.7 $130.5 may enter into in the future to manage our risk, over time as Hydroelectric 55.8 57.3 the contracts and related hedges settle in accordance with their Geothermal 46.3 56.0 terms. We do not expect to realize the value of these contracts Biomass 50.2 51.4 and related hedges by selling or assigning the contracts Fuel Processing 22.5 22.5 themselves in total. Solar 10.4 10.5 The fair values in the table represent expected future cash Total $313.9 $328.2 flows based on the level of forward prices and volatility factors as of December 31, 2004 and could change significantly as a result of future changes in these factors. Additionally, because the depth and liquidity of the power markets vary substantially between regions and time periods, the prices used to determine fair value could be affected significantly by the volume of transactions executed.
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\%Ve believe the current market conditions for our equity- Operating Fxpenses method investments that own geothermal, coal, hydroelectric, Our merchant energy business operating expenses increased and fuel processing projects provide sufficient positive cash flows $242.5 million in 2004 compared to 2003 mostly due to the to recover our investments. We continuously monitor issues that following:
potentially could impact future profitability of these investments,
- an increase of $94.3 million primarily related to higher including environmental and legislative initiatives. We discuss compensation, benefit, and other inflationary costs, certain risks and uncertainties in more detail in our Forward higher Sarbanes-Oxley 404 implementation costs of Looking Statements section. However, should future events cause approximately $10 million, and higher spending on these investments to become uneconomic, our investments in enterprise-wide information technology infrastructure these projects could become impaired under the provisions of costs of approximately $5 million, APB No. 18.
- an increase at our competitive supply operations totaling The ability to recover our costs in our equity-method $90.1 million mostly because of higher compensation investments that own biomass and solar projects is partially and benefit expense, including an increased number of dependent upon subsidies from the State of California. Under employees to support the growth of these operations, the California Public Utility Act, subsidies currently exist in that
- an increase in expenses due to the June 2004 acquisition the California Public Utilities Commission (CPUC) requires of Ginna totaling $43.1 million, and electric corporations to identify a separate rate component to
- an increase of $10.1 million at our Nine Mile Point fund the development of renewable resources technologies, nuclear facility primarily due to refueling outage and including solar, biomass, and wind facilities. In addition, reliability spending.
legislation in California requires that each electric corporation Our merchant energy business operating expenses increased increase its total procurement of eligible renewable energy $176.1 million in 2003 compared to 2002 mostly due to the resources by at least one percent per year so that 20% of its following:
retail sales are procured from eligible renewable energy resources
- an increase of $81.5 million due to the acquisitions of by 2017. The legislation also requires the California Energy our retail electric operation in September 2002 and Commission to award supplemental energy payments to electric retail gas operation in December 2002, corporations to cover above-market costs of renewable energy.
- an increase of S22.7 million at Nine Mile Point, Given the need for electric power and the desire for including higher costs associated with the refueling renewable resource technologies, we believe California will outage of Unit I in 2003 compared to the 2002 continue to subsidize the use of renewable energy to make these refueling outage of Unit 2. Since we own 100% of projects economical to operate. However, should the California Unit 1, we incurred all outage costs compared to 82%
legislation fail to adequately support the renewable energy of costs for Unit 2, initiatives, our equity-method investments in these types of
- costs of $17.8 million related to our High Desert projects could become impaired under the provisions of APB facility that commenced operations in the second No. 18, and any losses recognized could be material. If our quarter of 2003, strategy were to change from an intent to hold to an intent to
- an increase in costs of $10.3 million related to our sell for any of our equiry-method investments in qualifying wholesale marketing and risk management operation as facilities or power projects, we would need to adjust their book a result of growth of this operation, and value to fair value, and that adjustment could be material. If we
- higher compensation, benefit, and other inflationary were to sell these investments in the current market, we may costs.
have losses that could be material. These increases were partially offset by cost reductions due to productivity initiatives including our corporate-wide workforce reduction programs.
Workforce Reduction Costs, Impairment Losses and Other Costs, and Net Loss on Sales ofAssets Our merchant energy business recognized expenses associated with our loss on discontinued operations, workforce reduction efforts, impairment losses and other costs, and a net loss on sales of assets as discussed in more detail in Note 2.
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Depreciationand Amortization Expense Regulated Electric Business Merchant energy depreciation and amortization expense Our regulated electric business is discussed in detail in Item 1.
increased S18.5 million in 2004 compared to 2003 mostly Business-Electric Business section.
because of $10.3 million of depreciation and amortization at Ginna which was acquired in June 2004 and $5.1 million Results related to our South Carolina synthetic fuel facility which was 2004 2003 2002 acquired in May 2003. (In millions)
Merchant energy depreciation and amortization expense Revenues $ 1,967.7 $ 1,921.6 $ 1,966.0 decreased $13.3 million in 2003 compared to 2002 mostly Electricity purchased for resale expenses (1,034.0) (1,023.5) (1,080.7) because of the adoption of SFAS No. 143. Under SFAS Operations and No. 143, a portion of the decommissioning amortization is maintenance expenses (304.2) (305.1) (260.4) included as 'Accretion of asset retirement obligations" expense Workforce reduction costs - (0.6) (34.0) beginning in 2003. In addition, beginning in 2003 we no longer Depreciation and amortization (194.2) (181.7) (174.2) include the expected net future costs of removal as a component Taxes other than income of depreciation expense. TIese decreases were partially offset by taxes (132.8) (130.2) (129.0) higher depreciation expense related to new generating facilities Income from Operations $ 302.5 $ 280.5 $ 287.7 that commenced operations in mid-2002 and High Desert that Net Income $ 131.1 $ 107.5 $ 99.3 commenced operations in 2003.
Special Items Included in Operations (after-tax)
Workforce reduction Accretion ofAsset Retirement Obligations costs $ - $ (0.4) $ (20.5)
On January 1, 2003, we adopted SFAS No. 143 that requires the accretion of the asset retirement obligation liability due to Above amounts include intercompany transactionseliminated in our the passage of time until the liability is settled. The increase in ConsolidatedFinancialStatements. Note 3 provides a reconciliation accretion expense of $10.5 million in 2004 compared to 2003 is of operatingresults by segment to our ConsolidatedFinancial primarily due to $6.9 million related to Ginna which was Statements. Certainprior-yearamounts have been reclassifiedto acquired in June 2004. conform with the currentyears presentation.
Net income from the regulated electric business increased in Taxes Other Than Income Taxes 2004 compared to 2003 mostly because of:
Merchant energy taxes other than income taxes increased
- increased revenues less electricity purchased for resale S2.3 million in 2004 compared to 2003 mostly because of expenses of $21.5 million after-tax in 2004 compared to S4.2 million of property taxes at Ginna which was acquired in 2003, which indudes $6.0 million after-tax related to June 2004, partially offset by lower property taxes at Nine Mile the shareholder return portion of the administrative fee Point. collected under Provider of Last Resort rates, Merchant energy taxes other than income taxes increased
- the absence of $19.4 million after-tax of incremental
$19.5 million in 2003 compared to 2002 mostly because of distribution service restoration expenses associated with gross receipt taxes associated with our retail electric operation of Hurricane Isabel in 2003, and
$17.5 million and property taxes on new generating facilities.
- lower interest expense of $10.0 million after-tax.
These favorable results were partially offset by the following:
- excluding the costs associated with Hurricane Isabel, we had increased operations and maintenance expenses of
$18.9 million after-tax in 2004 compared to 2003 mostly due to higher compensation, benefit, and other inflationary costs, higher uncollectible expenses, Sarbanes-Oxley 404 implementation costs, and increased spending on electric system reliability, and
- increased depreciation and amortization expense of
$7.6 million after-tax.
Net income from the regulated electric business increased in 2003 compared to 2002 mostly because of:
- lower workforce reduction costs of $20.1 million after-tax,
- lower interest expense of $19.1 million after-tax, and
- cost reductions resulting from our corporate-wide workforce reduction programs and other productivity initiatives.
42
These favorable results were partially offset by distribution 2002 and elected other electric generation suppliers. In 2003, service restoration expenses related to Hurricane Isabel and other these decreased revenues were partially offset by an increase in major storms in 2003. Total distribution service restoration the standard offer service rate that BGE charges its customers.
expenses related to Hurricane Isabel were $22.2 million after-tax.
which included $19.4 million of incremental expenses. Electricity Purchasedfor Resal Expenses BGE's actual costs of electricity purchased for resale expenses Electric Revenues increased in 2004 compared to 2003 mostly due to increased The changes in electric revenues in 2004 and 2003 compared to sales to residential customers, partially offset by lower electricity the respective prior year were caused by- purchased for resale expenses associated with commercial and industrial customers that elected an alternative supplier 2004 2003 beginning July 1, 2004. Electricity purchased for resale expenses (In millions) decreased in 2003 compared to 2002 mostly because large Distribution volumes $15.8 S 3.0 commercial and industrial customers left BGE's standard offer Standard offer service 26.6 (54.2) service in the second quarter of 2002 and elected other electric Total change in elecric revenues from electric generation suppliers.
system sales 42.4 (51.2)
Other 3.7 6.8 Electric Operations and Maintenance Expenses Total change in electric revenues $46.1 $(44.4) Regulated electric operations and maintenance expenses were about the same in 2004 compared to 2003. Hurricane Isabel Distribution Volumes caused $32.1 million of incremental distribution service Distribution volumes are sales to customers in BGE's service restoration expenses in 2003. Other operations and maintenance territory for the delivery service BGE provides at rates set by the expenses increased $31.2 million in 2004 compared to 2003.
Maryland PSC. This increase was mostly due to:
The percentage changes in our electric system distribution
- an increase in compensation, benefit, and other volumes, by type of customer, in 2004 and 2003 compared to inflationary costs, the respective prior year were:
- a $9.0 million increase in uncollectible expenses,
- approximately $4 million related to Sarbanes-Oxley 404 2004 2003 implementation costs, and
- approximately $4 million in spending on electric systems Residential 4.4% 0.8%
Commercial 0.9 2.1 reliability.
Industrial (8.0) (3.0) Regulated electric operations and maintenance expenses increased $44.7 million in 2003 compared to 2002 mostly In 2004, we distributed more electricity to residential because of distribution service restoration expenses related to customers compared to 2003 mostly due to increased usage per Hurricane Isabel of $36.8 million, which includes $4.7 million customer, an increased number of customers, and warmer of non-incremental labor expenses, and distribution service summer weather. We distributed about the same amount of restoration expenses related to other major storms. This increase electricity to commercial customers. We distributed less also reflects higher compensation, benefit, and other inflationary electricity to industrial customers mostly due to lower usage by costs, partially offset by lower uncollectible expenses and cost industrial customers. reductions resulting from our corporate-wide workforce In 2003, we distributed about the same amount of reduction programs and other productivity initiatives.
electricity to residential customers compared to 2002. We distributed more electricity to commercial customers mostly due Workforce Reduction Costs to increased usage per customer. We distributed less electricity to BGE's electric business recognized expenses associated with our industrial customers mostly due to lower usage by industrial workforce reduction efforts as discussed in Note 2.
customers.
Electric Depreciation andAmortization Expense Standard Offer Service Regulated electric depreciation and amortization expense BGE provides standard offer service for customers that do not increased $12.5 million in 2004 compared to 2003 mostly select an alternative generation supplier as discussed in Item 1. because of $7.6 million related to accelerated amortization Business-Electric Regulatory Matters and Competition section. expense associated with the replacement of information Standard offer service revenues increased in 2004 compared technology assets and $4.9 million related to additional property to 2003 mostly because of increased distribution volumes to placed in service.
residential customers, partially offset by lower revenues associated Regulated electric depreciation and amortization expense with commercial and industrial customers that elected an increased $7.5 million in 2003 compared to 2002 mostly alternative supplier beginning July 1, 2004. Standard offer because of accelerated amortization associated with the service revenues decreased in 2003 compared to 2002 mostly replacement of information technology assets.
because a majority of BGE's large commercial and industrial customers left standard offer service in the second quarter of 43
Regulated Gas Business Gas Revenues All BGE customers have the option to purchase gas from other The changes in gas revenues in 2004 and 2003 compared to the suppliers. To date, customer choice has not had a material effect respective prior year were caused by.
on our, or BGEs, financial results.
2004 2003 Results (In millions) 2004 2003 2002 Distribution volumes $ (7.2) $ 21.6 (In millions) Base rates (0.1) (1.3)
Revenues $ 757.0 $ 726.0 $ 581.3 Weather normalization 5.4 (18.9)
Gas purchased for resale Gas cost adjustments 40.5 132.4 expenses (484.3) (445.8) (316.7)
Total change in gas revenues from gas system Operations and maintenance sales 38.6 133.8 expenses (123.6) (101.1) (106.2)
Off-system sales (7.6) 10.0 Workforce reduction costs (0.1) (1.3) Other - 0.9 Depreciation and amortization (48.1) (46.6) (47.4)
Taxes other than income taxes (32.1) (27.9) (31.1) Total change in gas revenues $31.0 $144.7 Income from Operations $ 68.9 $ 104.5 $ 78.6 Distribution Volumes Net Income $ 22.2 $ 43.0 $ 31.1 The percentage changes in our distribution volumes, by type of Special Items Included in Operations (afier-tax) customer, in 2004 and 2003 compared to the respective prior Workforce reduction costs $ - $ (0.1) $ (0.8) year were:
Above amounts include intercompany transactionseliminated in our ConsolidatedFinancialStatements. Note 3 provides a reconciliation 2004 2003 of operating results by segment to our ConsolidatedFinancial Residential (5.1)% 13.8%
Statements. Certainprior-yearamounts have been reclassifiedto Commercial 10.1 7.6 conform with the current yearl presentation. Industrial (22.3) (21.5)
Net income from our regulated gas business decreased during We distributed less gas to residential customers during 2004 2004 compared to 2003 mostly because of: compared to 2003 mostly due to milder winter weather and
- increased operations and maintenance expenses of lower usage per customer. We distributed more gas to
$13.6 million after-tax mostly due to increased commercial customers mostly due to increased usage and an compensation, benefit, and other inflationary costs, increased number of customers. WVe distributed less gas to higher uncollectible expenses, and Sarbanes-Oxley 404 industrial customers mostly due to lower usage per customer.
implementation costs, We distributed more gas to residential and commercial
- the absence of a $4.7 million after-tax recovery of a customers during 2003 compared to 2002 mostly due to colder previously disallowed regulatory asset following an order winter weather, an increased number of customers, and increased issued by the Maryland PSC that had a positive impact usage per customer. We distributed less gas to industrial in 2003, and customers mostly due to decreased usage per customer.
- the absence of $2.2 million after-tax of property tax refund claims by the State of Maryland resulting from a Weather NVormalzation reclassification of gas distribution pipeline from real The Maryland PSC allows us to record a monthly adjustment to property to personal property that had a positive impact our gas distribution revenues to eliminate the effca of abnormal in 2003. weather patterns on our gas distribution volumes. This means Net income from our regulated gas business increased our monthly gas distribution revenues are based on weather that during 2003 compared to 2002 mostly because of: is considered 'normal' for the month and, therefore, are not
- a $4.7 million after-tax recovery of a previously affected by actual weather conditions.
disallowed regulatory asset following an order issued by the Maryland PSC, and Gas Cost Adjustments
- the approval of $2.2 million after-tax of property tax We charge our gas customers for the natural gas they purchase refund daims by the State of Maryland resulting from a from us using gas cost adjustment clauses set by the Maryland reclassification of gas distribution pipeline from real PSC as described in Note! . However, under the market-based property to personal property. rates mechanism approved by the Maryland PSC, 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.
44
Customers who do not purchase gas from BGE are not Gas PurchasedFor Resale Expenses subject to the gas cost adjustment clauses because we are not Gas purchased for resale expenses include the cost of gas selling gas to them. However, these customers are charged base purchased for resale to our customers and for off-system sales.
rates to recover the costs BGE incurs to deliver their gas through These costs do not include the cost of gas purchased by delivery our distribution system, and are included in the gas distribution service only customers.
volume revenues. Gas costs increased during 2004 as compared to 2003 Gas cost adjustment revenues increased during 2004 mostly because of higher average gas prices and the $7.7 million compared to 2003 because we sold gas at a higher price partially recovery of disallowed fuel-related costs recognized in 2003 that offset by less gas sold. Gas cost adjustment revenues increased had a positive impact in that period as previously discussed in during 2003 compared to 2002 because we sold more gas at a the Gas Cost Adjustments section.
higher price. Gas costs increased during 2003 as compared to 2002 In December 2002, a Hearing Examiner from the mostly because we purchased more gas at a higher price.
Maryland PSC issued a proposed order disallowing $7.7 million of a previously established regulatory asset for certain credits that Gas OperationsandMaintenance Ewpenses were over-refunded to customers through our market-based rates. Regulated gas operations and maintenance expenses increased BGE reserved the $7.7 million of disallowed fuel costs in the $22.5 million during 2004 compared to 2003 mostly because of:
fourth quarter of 2002. In August 2003, the Maryland PSC
- an increase in compensation, benefit, and other issued an order authorizing us to recover the $7.7 million and inflationary expenses, we reinstated the regulatory asset.
- a $5.4 million increase in uncollectible expenses, and
- approximately $1 million related to Sarbanes-Oxley 404 Off-System Sales implementation costs.
Off-system gas sales are low-margin direct sales of gas to Regulated gas operations and maintenance expenses wholesale suppliers of natural gas outside our service territory. decreased $5.1 million during 2003 compared to 2002 mostly Off-system gas sales, which occur after BGE satisfied its because of lower uncollectible expenses and cost reductions customers' demand, are not subject to gas cost adjustments. The resulting from our corporate-wide workforce reduction programs Maryland PSC approved an arrangement for part of the margin and other productivity initiatives.
from off-system sales to benefit customers (through reduced costs) and the remainder to be retained by BGE (which benefits Workforce Reduction Costs shareholders). Changes in off-system sales do not significantly BGE's gas business recognized expenses associated with our impact earnings. workforce reduction efforts as discussed in Note 2.
Revenues from off-system gas sales decreased during 2004 compared to 2003 mostly because of less gas sold.
Revenues from off-system gas sales increased during 2003 compared to 2002 because we sold gas at a higher price, partially offset by less gas sold.
45
Other Nonregulated Businesses
- a $9.5 million pre-tax charge associated with the exit of Results BGE Home merchandise stores in 2002 which had a 2004 2003 2002 negative impact in that period.
(In milionj)
- a $7.2 million pre-tax gain on the sale of an oil tanker Revenues S 422.0 S 587.9 S 537.4 to the U.S. Navy, Operating expenses (353.4) (535.8) (505.9)
- a $5.3 million pre-tax gain on the favorable settlement Workforce reduction costs - (0.2) (1.0) of a contingent obligation we had previously reserved Impairment losses and other costs (3.7) (0.6) (10.8) relating to the sale of our Guatemalan power plant Depreciation and amortization (35.2) (21.2) (16.6) operation in the fourth quarter of 2001.
Taxes other than income taxes (2.5) (3.3) (4.3)
- a $0.6 million pre-tax gain on the sale of financial Net (loss) gain on sales of investments investments, and and other assets (1.2) 26.2 265.0
- improved results from our international portfolio.
Income from Operations S 26.0 S 53.0 S 263.8 In 2001, we decided to sell certain non-core assets and Net (Loss) Income $ (3.5) $ 12.2 $ 148.0 accelerate the exit strategies on other assets that we continued to hold and own. These assets indcluded approximately 1,300 acres Special Items Included In Operations(afer-tax)
Impairment of real estate, senior- of land holdings in various stages of development located in living, and other investments S (2.2) S (0.4) S (1.2) seven sites in the central Maryland region, an operating waste Net (loss) gain on sales of water treatment plant located in Anne Arundel County, investments and other assets (0.6) 16.4 169.1 Maryland, all of our 18 senior-living facilities and certain Workforce reduction costs (0.1) (0.7) international power projects. At December 31, 2004, our Costs associated with exit of BGE remaining land holdings totaled approximately 190 acres with a Home merchandise stores - - (6.1) carrying value of approximately $29 million recorded in our Total Special Items S (2.8) $ 15.9 $ 161.1 Consolidated Balance Sheets. We also initiated a liquidation Above amounts include intercompany transactionseliminated in our program for our financial investments operation in 2001. As of December 31, 2004. we have substantially liquidated our ConeoidatedFinancalStatements. Note 3 prcvides a reconcliation investment portfolio and have approximately $6 million in of operating results by segment to our ConsolidatedFinancial non-core financial investments recorded in our Consolidated Statements.
Balance Sheets.
Net income from our other nonregulated businesses decreased In 2005, we began to market our Panamanian distribution
$15.7 million during 2004 compared to 2003 mostly because of facility and our investment in a fund that owns interests in two a S16.4 million net gain on sales of investments and other assets South American energy projects, with an expectation of in 2003 that had a positive impact in that period. completing a sale by the end of the year. We do not expect that Ner income from our other nonregulared businesses the sale of these assets will have a material impact on our decreased $135.8 million during 2003 compared to 2002 mostly financial results.
because we recognized a $163.3 million after-tax gain on the sale While our intent is to dispose of these remaining non-core of our investment in Orion in 2002 that had a positive impact assets, market conditions and other events beyond our control in that period. This decrease was partially offset by the following may affect the actual sale of these assets. In addition, a future 2003 transactions: decline in the fair value of these assets could result in losses that
- a $13.1 million pre-tax gain on the sale of several could have a material impact on our financial results.
parcels of real estate, 46
Consolidated Nonoperating Income and Expenses Income Taxes Other Income The differences in income taxes result from a combination of Other income decreased $5.0 million during 2004 as compared the changes in income and the impact of the recognition of tax to 2003 mostly because of higher earnings from consolidated credits on the effective tax rate. We include an analysis of the investments where our ownership is less than 100%, which changes in the effective tax rate and discuss in more detail the resulted in increased minority interest expense. Other income tax credits related to our South Carolina synthetic fuel facility in decreased $11.4 million during 2003 as compared to 2002 Note 10.
mostly because of lower interest income on temporary cash investments of $6.1 million and higher earnings from Pension Expense consolidated investments where our ownership is less than Our actual return on our qualified pension plan assets was 100%, which resulted in increased minority interest expense of 11.6% for the year ended December 31, 2004. We assume an
$4.0 million. expected return on pension plan assets of 9% for the purpose of Other income for BGE decreased $16.1 million in 2003 as computing annual net periodic pension expense in accordance compared to 2002 mostly because of an increase in charitable with SFAS No. 87. Emp/yers'Arountingfr Pensions. Differences contributions of $7.5 million and because of lower interest between actual and expected returns are deferred along with income of $5.0 million on temporary cash investments in the other actuarial gains and losses and reflected in future net Constellation Energy cash pool. periodic pension expense in accordance with SFAS No. 87.
Expected and actual returns on pension assets also are affected Fixed Charges by plan contributions.
Total fixed charges decreased $9.9 million during 2004 as We contributed an additional $50 million to our pension compared to 2003 mostly because of a lower level of debt plans in March 2005, even though there is no IRS minimum outstanding and the benefit of lower interest rates due to interest contribution for 2005. At December 31. 2004, we recorded an rare swaps entered into during the third quarter of 2004. We after-tax charge to equity of $42.6 million as a result of discuss these interest rate swaps in more detail in Note 13. increasing our additional minimum pension liability. We discuss Total fixed charges increased $58.7 million during 2003 our pension plans in more detail in Note 7.
compared to 2002 mostly because we had lower capitalized interest of $30.2 million due to our new generating facilities commencing operations and $28.5 million related to a higher level of debt outstanding, including the issuance of $550 million of debt in June 2003 that was used to refinance the High Desert facility lease.
Total fixed charges for BGE decreased $15.0 million during 2004 compared to 2003 mostly because of a lower level of debt outstanding. Total fixed charges for BGE decreased
$29.4 million during 2003 compared to 2002 mostly because of a lower level of debt outstanding and lower interest rates.
47
Financial Condition Cash Flows The following table summarizes our 2004 cash flows by business segment, as well as our consolidated cash flows for 2004, 2003, and 2002.
2004 Segment Cash Flows Consolidated Cash Flows Merchant Regulated Other 2004 2003 2002 (In millions)
Operating Activities Net Income $ 389.9 $ 153.3 $ (3.5) $ 539.7 $ 277.3 $ 525.6 Non-cash adjustments to net income 592.9 293.1 44.3 930.3 959.5 616.0 Changes in working capital (318.8) (43.1) 32.3 (329.6) (65.3) 49.0 Pension and postemployment benefits' (3.0) (69.4) (116.2)
Other (41.2) (28.0) 18.6 (50.6) (44.3) (68.6)
Net cash provided by operating activities 622.8 375.3 91.7 1,086.8 1,057.8 1,005.8 Investing activities Investments in property. plant and equipment (428.3) (242.1) (33.2) (703.6) (635.7) (817.7)
Acquisitions, net of cash acquired (457.3) - - (457.3) (546.6) (221.4)
Contributions to nudear decommissioning trust funds (22.0) - - (22.0) (13.2) (17.6)
Net proceeds from sale of discontinued operations 72.7 - - 72.7 - -
Sale of investments and other assets 0.1 4.9 31.1 36.1 148.8 838.0 Other investments (86.1) - 7.5 (78.6) (113.6) (86.9)
Net cash (used in) provided by investing activities (920.9) (237.2) 5.4 (1,152.7) (1,160.3) (305.6)
Cash flows forom operating activities less cash flows from investing activities $(298.1) $ 138.1 $ 97.1 (65.9) (102.5) 700.2 Financing Activities Net (repayment) issuance of debt' (152.8) 274.9 (62.9)
Proceeds from issuance of common stock' 293.9 95.4 28.5 Common stock dividends paid* (189.7) (169.2) (137.8)
Other' 99.5 7.7 14.6 Net cash provided by (used in) financing activities 50.9 208.8 (157.6)
Net (Decrease) Increase in Cash and Cash Equivalents $ (15.0) $ 106.3 $ 542.6
'Items are not allocated to the business segments because thy are managedfr the company as a whole.
Cash Flowsfrom OperatingActivities
- a decrease in the net gain on sales of investments and Cash provided by operating activities was $1,086.8 million in other assets of $27 million primarily due to the sale of 2004 compared to $1,057.8 million in 2003 and financial and real estate investments in 2003. We adjust
$1,005.8 million in 2002. Net income was higher by net income to exclude these gains and reflect the
$262.4 million in 2004 compared to 2003. Non-cash proceeds from these sales in the investing activities adjustments to net income were $29.2 million lower in 2004 section.
compared to 2003. The decrease in non-cash adjustments to net Changes in working capital had a negative impact of income was primarily due to the cumulative effects of changes in $329.6 million on cash flow from operations in 2004 compared accounting principles of $198.4 million as a result of the to a negative impact of $65.3 million in 2003. The adoption of SFAS No. 143 and EITF 02-3 in 2003, which had $264.3 million decrease was primarily due to the following uses the effect of reducing net income in 2003 but were non-cash of cash in 2004 compared to 2003:
transactions. This decrease in non-cash adjustments to net
- a decline in working capital related to accrued taxes of income was offset in part by the following increases in non-cash approximately $254 million in 2004 compared to 2003 adjustments in 2004: due to higher income tax payments in 2004 compared
- higher depreciation and amortization and accretion of to refunds of taxes in 2003 and due to the timing of asset retirement obligations of $60 million, income tax accruals in 2004 compared to 2003,
- the loss from discontinued operations of $49 million,
- a $77 million unfavorable change in working capital
- an increase in deferred income taxes of $14 million, and relating to our accounts receivable and accounts payable primarily due to increased volumes associated with our merchant energy business and the termination of an accounts receivable securitization program in 2004, and 48
- an unfavorable change of approximately $49 million property, plant and equipment and a decrease in cash proceeds relating to fuel stocks during 2004 primarily due to from the sale of investments and other assets in 2004 compared higher gas and coal prices, which affected inventory to 2003.
levels at BGE and our merchant energy business. The $854.7 million increase in cash used in investing These items were partially offset by a $111 million source activities in 2003 compared to 2002 was primarily due to a of cash in 2004 compared to 2003 primarily due to other decrease in cash proceeds from the sales of investments and favorable working capital changes as a result of higher accrued other assets in 2003 because of the sale of Orion and Corporate expenses in 2004 compared to 2003. Office Property Trust that generated $555.4 million in 2002.
Cash provided by operating activities was $1,057.8 million We discuss our sale of Orion in Note 2. In addition, acquisitions in 2003 compared to $1,005.8 million in 2002. Non-cash were $325.2 million higher in 2003 due to the refinancing of adjustments to net income were $343.5 million higher in 2003 the High Desert lease, partially offset by a decline in other compared to 2002. The increase in non-cash adjustments to net acquisitions from 2002.
income was primarily due to the following:
- cumulative effects of changes in accounting principles of Cash Flowsfrom FinancingActivitirs
$198.4 million as a result of the adoption of SFAS Cash provided by financing activities was $50.9 million in 2004 No. 143 and EITF 02-3 in 2003, which had the effect compared to $208.8 million in 2003. The decrease in 2004 of reducing net income but were non-cash transactions, compared to 2003 was mostly due to a lower issuance of net and debt in 2004 (gross proceeds less debt repayments), partially
- a decrease in the net gain on sales of investments and offset by higher proceeds from common stock issuances and other assets of $235.1 million primarily due to the sale acquired contracts in 2004. We discuss cash flows from customer of our investment in Orion in 2002. contract restructurings in more detail below.
These increases in non-cash adjustments to net income Cash provided by financing activities increased were offset in part by lower accruals for workforce reduction $366.4 million in 2003 compared to 2002 mostly due to higher costs of $60.7 million in 2003 compared to 2002. net issuances of debt in 2003 compared to 2002.
Changes in working capital had a negative impact of
$65.3 million on cash flow from operations in 2003 compared Cash Flows from Customer Contract Restructurings to a positive impact of $49.0 million in 2002. The During 2004, our merchant energy business entered into several
$114.3 million decrease was primarily due to the following uses power agreements to help customers restructure their businesses, of cash in 2003 compared to 2002: which generate significant cash flows at the inception of the
- an increase in cash in 2002 due to the collection of contracts. These agreements have a contract price that differs approximately $85 million related to prepaid expenses from current market prices, which results in cash payments from and collateral at our retail electric operation subsequent the counterparty at the inception of the contract. We received to our acquisition, $117.5 million in 2004 for one contract reflected in cash flows
- a decline in accrued interest of approximately from financing activities in our Consolidated Statements of Cash
$50 million in 2003 compared to 2002 due to a shift in Flows. We received an additional $157.2 million for a second the timing of interest payments as a result of financings contract in March 2005. We expect to receive approximately in 2002, $70 million in the first half of 2005 for another contract that
- an increase of approximately $40 million in fuel stocks was entered into during 2004, contingent upon the receipt of all and materials and supplies during 2003 primarily due to regulatory and other approvals and the closing of the higher gas prices, which affected BGE's inventory levels, transaction.
and
- an increase of approximately $54 million in our Security Ratings accounts receivable balance primarily related to our Independent credit-rating agencies rate Constellation Energy's merchant energy business as a result of increased and BGE's fixed-income securities. The ratings indicate the business and High Desert commencing operations in agencies' assessment of each company's ability to pay interest, 2003. distributions, dividends, and principal on these securities. These These items were partially offset by a source of cash in ratings affect how much it will cost each company to sell these 2003 compared to 2002 due to an increase in accrued income securities. The better the rating, the lower the cost of the taxes. securities to each company when they sell them.
The factors that credit rating agencies consider in Cash Flows from Investing Activities establishing Constellation Energy's and BGE's credit ratings Cash used in investing activities was $1,152.7 million in 2004 include, but are not limited to, cash flows, liquidity, business compared to $1,160.3 million in 2003 and $305.6 million in risk profile, and the amount of debt as a component of total 2002. Cash used in investing activities in 2004 was about the capitalization. In March 2004, Standard & Poors rating group same as in 2003 primarily due to the decrease in cash used for reduced Constellation Energy's and BGE's corporate credit rating acquisitions and proceeds from the sale of discontinued from A- to BBB+ and reduced certain other ratings to the levels operations in 2004, substantially offsetting increased spending on noted in the table on the next page. In October 2004, Fitch-49
Ratings affirmed Constellation Energy's and BGEs credit ratings. We expect to fund future acquisitions with an overall goal All Constellation Energy and BGE credit ratings have stable of maintaining a strong investment grade credit profile. We outlooks. At the date of this report, our credit ratings were as funded our June 2004 acquisition of Ginna with a mix of cash follows: and equity. On July 1, 2004, we issued 6.0 million shares of Standard common stock for net proceeds of $226.9 million to fund a
& Poors Moody's portion of the acquisition of Ginna. We discuss our acquisition Raing Investors Fitch- of Ginna in more detail in Note 15.
Group Service Ratings Constellation Energy BGE Commercial Paper A-2 P-2 F-2 During 2004, certain credit facilities expired and BGE renewed Senior Unsecured Debt' BBB Baal A- those facilities. BGE continues to maintain $200.0 million in BGE annual committed credit facilities, expiring May through Commercial Paper A-2 P-1 F-I November 2005, to ensure adequate liquidity to support its Mortgage Bonds A Al A+ operations. We can borrow directly from the banks or use the Senior Unsecured Debt BBB+ A2 A facilities to allow commercial paper to be issued. As of Trust Preferred Securities' BBB- A3 A- December 31, 2004, BGE had no outstanding commercial Preference Stock' BBB- Baal A- paper, which results in $200.0 million in unused credit facilities.
'In March 2004. Standard & Poors ratinggroup reduced the rating one level to this current rating. Other Nonregulated Businesses BGE Home Products & Services' program to sell up to Available Sources of Funding $50 million of receivables was not extended beyond the We continuously monitor our liquidity requirements and believe March 2004 expiration date. During 2004, this receivables that our credit facilities and access to the capital markets provide program was fully liquidated.
sufficient liquidity to meet our business requirements. We If we can get a reasonable value for our remaining real discuss our available sources of funding in more detail below. estate projects and other investments, additional cash may be obtained by selling them. Our ability to sell or liquidate assets ConstellationEnergy will depend on market conditions, and we cannot give In addition to our cash balance, we have a commercial paper assurances that these sales or liquidations could be made.
program under which we can issue short-term notes to fund our subsidiaries. At December 31, 2004, we had approximately Capital Resources
$2.2 billion of credit under several facilities. Our actual consolidated capital requirements for the years 2002 In June 2004, Constellation Energy arranged an through 2004, along with the estimated annual amount for
$800.0 million three-year revolving credit facility and a 2005, are shown in the table on the next page.
S300.0 million five-year revolving credit facility replacing a We will continue to have cash requirements for:
$447.5 million 364-day revolving credit facility, which expired in
- working capital needs, the second quarter of 2004. We also have an existing
- payments of interest, distributions, and dividends,
$640 million revolving credit facility expiring in June 2005 and
- capital expenditures, and a $447.5 million facility expiring in June 2006.
- the retirement of debt and redemption of preference We use these facilities to ensure adequate liquidity to stock.
support our operations. We can borrow directly from the banks Capital requirements for 2005 and 2006 include estimates or use the facilities to allow the issuance of commercial paper. of spending for existing and anticipated projects. We Additionally, we use the multi-year facilities to support letters of continuously review and modify those estimates. Actual credit primarily for our merchant energy business. requirements may vary from the estimates included in the table These revolving credit facilities allow the issuance of letters on the next page because of a number of factors including:
of credit up to approximately $2.2 billion. In addition, BGE
- regulation, legislation, and competition, maintains $200.0 million in credit facilities as discussed below.
- BGE load requirements, At December 31, 2004, letters of credit that totaled
- environmental protection standards,
$809.9 million were issued under all of our facilities.
- the type and number of projects selected for In October 2004, we terminated certain loans under other construction or acquisition, revolving credit agreements of $41A million related to our
- the effect of market conditions on those projects, Panamanian distribution facility. We replaced these revolving
- the cost and availability of capital, credit agreements with loans under new revolving credit
- the availability of cash from operations, and agreements totaling $100.0 million.
- business decisions to invest in capital projects.
50
Our estimates are also subject to additional factors. Please
- upstream gas investments, see the ForivardLooking Statements section.
- portfolio acquisitions and other investments,
- costs of complying with the Environmental Protection 2002 2003 2004 2005 Agency (EPA), Maryland, and Pennsylvania nitrogen oxides (NOx) and sulfur dioxide (SO 2 ) emissions (In millions)
Nonregulated Capital Requirements: regulations, and Merchant energy (excludes
- enhancements to our information technology acquisitions) infrastructure.
Construction program $122 $ - S- $ -
Generation plants 236 175(A)182 180 RegulatedElectric and Gas Nuclear fuel 122 59 133 125 Regulated electric and gas construction expenditures primarily Environmental controls 66 12 - 5 include new business construction needs and improvements to Portfolio acquisitions/investments 51 51 11 140 existing facilities, including projects to improve reliability.
Technology/other 44 122 129 125 Capital requirements for 2003 in the table above include
$32.0 million in costs incurred as a result of Hurricane Isabel to Total merchant energy capital restore the electric distribution system.
requirements 641 419 455 575 Other nonregulared capital Funding for Capital Requirements requirements 65 53 42 35 Merchant Energy Business Total nonregulated capital Funding for the expansion of our merchant energy business is requirements 706 472 497 610 expected from internally generated funds. We also have available Regulated Capital Requirements: sources from commercial paper issuances, issuances of long-term Regulated electric 167 236 209 250 debt and equity, leases, and other financing activities.
Regulated gas 50 53 56 55 The projects that our merchant energy business develops typically require substantial capital investment. Many of the Total regulated capital requirements 217 289 265 305 qualifying facilities and independent power projects that we have Total capital requirements $923 $761 $762 $915 an interest in are financed primarily with non-recourse debt that is repaid from the project's cash flows. This debt is collateralized (A) The table above does not include the capital requirements and financing costs of approximately $40 million for the by interests in the physical assets, major project contracts and High Desert Power Project for the six months ended agreements, cash accounts and, in some cases, the ownership interest in that project.
June 30, 2003. We discuss the acquisition of the High Desert Power Project in Note 15. We expect to fund acquisitions with a mixture of debt and The above amounts do not include the acquisition of Ginna but do equity with an overall goal of maintaining a strong investment grade credit profile.
include post-acquisitioncapital requirrmentsfirGinna. We discuss the acquisition of Ginna in more detail in Note 15.
Regulated Electric and Gas As of the date of this report, we have not completed our Funding for regulated electric and gas capital expenditures is 2006 capital budgeting process, but expect our 2006 capital expected from internally generated funds. During 2005, we requirements to be approximately $950 million. expect our regulated business to generate sufficient cash flows Our environmental controls capital requirements are from operations to meet BGE's operating requirements. If affected by nenv rules or regulations that require modifications to necessary, additional funding may be obtained from commercial our facilities. As a result of regulatory or legislative proposals, we paper issuances, available capacity under credit facilities, the expect more stringent air emission standards to be adopted and issuance of long-term debt, trust preferred securities, or if promulgated as expected we will install additional air emission preference stock, and/or from time to time equity contributions control equipment at our coal-fired generating facilities in from Constellation Energy. BGE also participates in a cash pool Maryland and at co-owned coal-fired generating facilities in administered by Constellation Energy as discussed in Note 16.
Pennsylvania. If these rules are promulgated as we have assumed in our projections, there would be another $400-$500 million of Other Nonregulated Businesses capital spending from 2008-2010. We discuss environmental Funding for our other nonregulated businesses is expected from matters in more detail in Item I.Business-Environmental internally generated funds, commercial paper issuances, issuances Matters. of long-term debt of Constellation Energy, sales of securities and assets, and/or from time to time equity contributions from Capital Requirements Constellation Energy.
Merchant Energy Business Our ability to sell or liquidate securities and non-core assets Our merchant energy business' capital requirements consist of its will depend on market conditions, and we cannot give continuing requirements, including expenditures for: assurances that these sales or liquidations could be made. We
- improvements to generating plants, discuss our remaining non-core assets and market conditions in
- nuclear fuel costs, the Results of Operations-OtherNonregulatedBusinesses section.
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Contractual Payment Obligations and Committed The table below presents our contingent obligations. Our Amounts contingent obligations increased $2.6 billion during 2004, We enter into various agreements that result in contractual primarily due to the issuance of additional letters of credit and payment obligations in connection with our business activities. guarantees by the parent company for subsidiary obligations to These obligations primarily relate to our financing arrangements third parties in support of the growth of our merchant energy (such as long-term debt, preference stock, and operating leases), business. These amounts do not represent incremental purchases of capacity and energy to support the growth in our consolidated Constellation Energy obligations; rather, they merchant energy business activities, and purchases of fuel and primarily represent parental guarantees of certain subsidiary transportation'to satisfy the fuel requirements of our power obligations to third parties. Our calculation of the fair value of generating facilities. subsidiary obligations covered by the $5,504.2 million of parent Our total contractual payment obligations as of company guarantees was $1,395.6 million at December 31, December 31, 2004 are shown in the following table: 2004. Accordingly, if the parent company was required to fund Payments subsidiary obligations, the total amount at current market prices 2006- 2008- is $1,395.6 million.
2005 2007 2009 Thereafter Total (In millions) Expiration ContractualPayment 2006- 2008-Obligations 2005 2007 2009 Thereafter Total Long-term debt:' (In milions)
Nonregulated Contingent Oblsiations Principal $ 314.5 $ 639.6$ 518.3 $2,328.1 $ 3,800.5 Letters of credit $ 787.5$ 22.4$ - $ - $ 809.9 Interest 215.7 398.9 335.0 1,584.2 2,533.8 Guarantees - competitive Total 530.2 1,038.5 853.3 3,912.3 6,334.3 supply' 3,693.4 918.5 314.5 577.8 5,504.2 BGE Other guarantees, net' 6.7 3.6 15.7 1,236.0 1,262.0 Principal 41.6 565.3 307.5 589.2 1,503.6 Total contingent obligations $4,487.6 $944.5 $330.2 $1,813.8 $7,576.1 Interest 87.4 138.6 79.2 809.0 1,114.2 I W7jie theface amount of these guarantees is $5.5042 miion, we would not Total 129.0 703.9 386.7 1,398.2 2,617.8 espect to fund the full amount. In the event the parent were required to fulfil BGE preference stock - - - 190.0 190.0 subsidiavy obgations. our calculation of the fair salue of obligations covered by Operating leases2 113.2 219.2 74.6 127.9 534.9 these guarantees was $1395.6 million at December31. 2004.
3 2 Other guarantees in the above table are shown net of liabilities of $25.0 million Purchase obligations:
recorded at December 31, 2004 in our CnsolidatedBalance Sheets.
Purchased capacity and energy' 794.2 743.3 184.9 157.0 1,879.4 Fuel and Liquidity Provisions transportation' 1,292.0 816.3 142.8 37.3 2,288.4 In many cases, customers of our merchant energy business rely Other 97.2 63.0 74.9 211.0 446.1 on the credieworthiness of Constellation Energy. A decline below Other noncurrent investment grade by Constellation Energy would negatively liabilities: impact the business prospects of that operation.
Postretirement and We regularly review our liquidity needs to ensure that we postemployment have adequate facilities available to meet collateral requirements.
benefits' 36.1 74.3 79.8 185.1 375.3 This includes having liquidity available to meet margin Other 1.6 - - - 1.6 requirements for our wholesale marketing and risk management Total contractual operation and our retail competitive supply activities.
payment obligations $2,993.5 $3,658.5 $1,797.0 $6,218.8 $14,667.8 We have certain agreements that contain provisions that I Amounts in long-term debt refeca the originalmaturity date. Investors may would require additional collateral upon credit rating decreases require us to repay $381.6 milton eary throughput options and remarketing in the senior unsecured debt of Constellation Energy. Decreases features. Interest on gariable rate debt is included based on the December 31.
2004forwartd curvefor interest rates. in Constellation Energy's credit ratings would not trigger an 2 Our operating lease commitments includefuturepayment obligations under early payment on any of our credit facilities.
certainpower purchase agreements as discussedfurtherin Note 11. Under counterparty contracts related to our wholesale 3 Contracts to purchase goods or services that sperify al significant terms. Amounts relatedto certainpurchase obligation are based onfuture purchase expdetations marketing and risk management operation, we are obligated to which may differfiom actual purchases. post collateral if Constellation Energy's senior unsecured credit 4 Our contractualobligationsforpurchaed capacity and energy are shown on a ratings declined below established contractual levels. As a result gross basisfor certain transactions. including both thefixed payment portions of totling contracts and etimated variablepayments under unit-contingentpower of the ratings action taken by Standard & Poors rating agency in purchase agreements. We have recorded $17.4 million of liabilities related to March 2004, we posted approximately $40 million in additional purchased capacity and energ obligations at December 31. 2004 in our collateral during the first quarter of 2004 to support our ConsolidatedBalance Sherts.
wholesale marketing and risk management operational WWe have recordedliabilitiesof $16.5 million relatedto fuel and transportation obligations at December 31, 2004 in our Consolidated Balance Sheets requirements. We discuss the Standard & Poors rating action in 6 Amounts related to postretirement andpostemployment benefits arefor unfunded more detail in the FinancialCondition-SecuritiesRatings plans and reflect present value amounts consistent with the determination of the section.
relatedliabilities recordedon the ConsolidatedBalance Sheets as discussed in Note 7.
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Based on contractual provisions at December 31, 2004, we cross-default provisions that apply to defaults on debt by estimate that if Constellation Energy's senior unsecured debt Constellation Energy and certain subsidiaries over a specified were downgraded we would have the following additional threshold. Certain BGE credit facilities also contain usual and collateral obligations: customary cross-default provisions that apply to defaults on debt by BGE over a specified threshold. The indentures pursuant to Credit Ratings Incremental Cumulative which BGE has issued and outstanding mortgage bonds and Downgraded to Obligations Obligations subordinated debentures provide that a default under any debt (in millions) instrument issued under the relevant indenture may cause a BBB-/Baa3 S13 S13 default of all debt outstanding under such indenture.
Below investment grade 662 675 Constellation Energy also provides credit support to Calvert Based on market conditions and contractual obligations at Cliffs, Nine Mile Point, and Ginna to ensure these plants have funds to meet expenses and obligations to safely operate and the time of a downgrade, we could be required to post collateral maintain the plants.
in an amount that could exceed the amounts specified above, which could be material. At December 31, 2004, we had We discuss our short-term credit facilities in Note 8, long-term debt in Note 9, kease requirements in Note 11, and approximately $1.6 billion of unused credit facilities and commitments and guarantees in Note 12.
$706.3 million of cash available to meet potential collateral requirements.
Off-Balance Sheet Arrangements The credit facilities of Constellation Energy and BGE have For financing and other business purposes, we utilize certain limited material adverse change clauses that only consider a off-balance sheet arrangements that are not reflected in our material change in financial condition and are not directly Consolidated Balance Sheets. Such arrangements do not affected by decreases in credit ratings. If these clauses are represent a significant part of our activities or a significant invoked, the lending institutions can decline to make new ongoing source of financing. We use these arrangements when advances or issue new letters of credit, but cannot accelerate the they enable us to obtain financing or execute commercial payment of existing amounts outstanding. The long-term debt transactions on favorable terms. As of December 31, 2004, we indentures of Constellation Energy and BGE do nor contain have no material off-balance sheet arrangements including:
material adverse change clauses or financial covenants.
- guarantees with third-parties that are subject to the Certain credit facilities of Constellation Energy contain a initial recognition and measurement requirements of provision requiring Constellation Energy to maintain a ratio of FASB Interpretation No. 45, Guarantor'sAccounting and debt to capitalization equal to or less than 65%. At Disclosure Requirementsfir Guarantees, Including Indirect December 31, 2004, the debt to capitalization ratios as defined in the credit agreements were no greater than 51%. Certain Guarantees of Indebtedness to Others,
- retained interests in assets transferred to unconsolidated credit agreements of BGE contain provisions requiring BGE to entities, maintain a ratio of debt to capitalization equal to or less than
- derivative instruments indexed to our common stock, 65%. At December 31, 2004, the debt to capitalization ratio for and classified as equity, or BGE as defined in these credit agreements was 46%. At
- variable interests in unconsolidated entities that provide December 31, 2004, no amount was outstanding under these financing, liquidity, market risk or credit risk support, agreements.
or engage in leasing, hedging or research and Failure by Constellation Energy, or BGE, to comply with development services.
these provisions could result in the maturity of the debt We discuss our guarantees in Note 12.
outstanding under these facilities being accelerated. The credit facilities of Constellation Energy contain usual and customary Market Risk limits. We have a Risk Management Department that is We are exposed to various risks, including, but not limited to, responsible for monitoring the key business risks, enforcing energy commodity price and volatility risk, credit risk, interest compliance with risk management policies and risk limits, as rate risk, equity price risk, foreign exchange risk, and operations well as managing credit risk. The Risk Management Department risk. Our risk management program is based on established reports to the Chief Risk Officer (CRO) who provides regular policies and procedures to manage these key business risks with risk management updates to the Audit Committee and the a strong focus on the physical nature of our business. This Board of Directors.
program is predicated on a strong risk management culture We have a Risk Management Committee (RMC) that is combined with an effective system of internal controls. responsible for establishing risk management policies, reviewing Our Board of Directors and the Audit Committee of the procedures for the identification, assessment, measurement and Board oversee the risk management program, including the management of risks, and the monitoring and reporting of risk approval of risk management policies and establishment of risk exposures. The RMC meets on a regular basis and is chaired by 53
the CRO and consists of our Chief Executive Officer, our Chief Interest Rate Risk Financial Officer and Chief Administrative Officer, our Executive We are exposed to changes in interest rates as a result of Vice President of Corporate Strategy & Development, the financing through our issuance of variable-rate and fixed-rate President of Constellation Energy Commodities Group, and the debt and certain related interest rate swaps. We may use President of Constellation Generation Group. In addition, the derivative instruments to manage our interest rate risks.
CRO coordinates with the risk management committees at the In July 2004, to optimize the mix of fixed and floating-rate major operating subsidiaries that meet regularly to identify. debt, we entered into interest rate swaps relating to $450 million assess, and quantify material risk issues and to develop strategies of our long-term debt. These fair value hedges effectively convert to manage these risks. our current fixed-rate debt to a floating-rate instrument tied to the three month London Inter-Bank Offered Rate. Including the
$450 million in interest rate swaps, approximately 15% of our long-term debt is floating-rate.
The following table provides information about our debt obligations that are sensitive to interest rate changes:
PrincipalPayments and Interest Rate Detail by ContractualMaturity Date Fair value at 2005 2006 2007 2008 2009 Thereafter Total Dec. 31, 2004 (Dollaramounts in millions)
Long-term debt Variable-rate debt $ 8.6 $100.9 $ 5.0 $ 5.0 $ 10.0 $ 766.1 $ 835.6 $ 835.6 Average interest rate 4.26% 2.57% 5.53% 5.53% 5.53% 3.00% 3.07%
Fixed-rate debt $347.5(A) $362.1 $736.9 $299.3 $511.5 $2,211.2 $4.468.5 $4,979.7 Average interest rate 7.61% 5.43% 6.49% 6.28% 6.12% 6.46% 6.43%
(A) Amount excludes $381.6 million of long-term debt that contains certain put options under which lenders could potentially require us to repay the debt priorto maturity of which $124.3 million is classified as currentportion of long-term debt in our Consolidated Balance Sheets and in our ConsolidatedStatements of Capitalization.
Commodity Risk the associated financial exposure, this commodity price volatility We are exposed to the impact of market fluctuations in the price could affect our earnings. These factors include:
and transportation costs of electricity, natural gas, coal, and
- seasonal daily and hourly changes in demand, other commodities. These risks arise from our ownership and
- extreme peak demands due to weather conditions, operation of power plants, the load-serving activities of BGE
- available supply resources, standard offer service and our competitive supply activities, and
- transportation availability and reliability within and our origination and risk management activities. We discuss these between regions, risks separately for our merchant energy and our regulated
- location of our generating facilities relative to the businesses below. location of our load-serving obligations,
- procedures used to maintain the integrity of the physical Merchant Energy Business electricity system during extreme conditions, and Our merchant energy business is exposed to various risks in the
- changes in the nature and extent of federal and state competitive marketplace that may materially impact its financial regulations.
results and affect our earnings. These risks include changes in These factors can affect energy commodity and derivative commodity prices, imbalances in supply and demand, and prices in different ways and to different degrees. These effects operations risk. may vary throughout the country as a result of regional differences in:
Commodity Prices
- weather conditions, Commodity price risk arises from:
- market liquidity,
- the potential for changes in the price of, and
- capability and reliability of the physical electricity and transportation costs for, electricity, natural gas, coal, and gas systems, and other commodities,
- the nature and extent of electricity deregulation.
- the volatility of commodity prices, and Additionally, we have fuel requirements that are subject to
- changes in interest rates and foreign exchange rates. future changes in coal, natural gas, and oil prices. Our power A number of factors associated with the structure and generation facilities purchase fuel under contracts or in the spot operation of the energy markets significantly influence the level market. Fuel prices may be volatile and the price that can be and volatility of prices for energy commodities and related obtained from power sales may not change at the same rate or derivative products. We use such commodities and contracts in in the same direction as changes in fuel costs. This could have a our merchant energy business, and if we do not properly hedge material adverse impact on our financial results.
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Supply and Demand Risk manage these risks, we may enter into fixed-price derivative or We are exposed to the risk that available sources of supply may non-derivative contracts to hedge the variability in future cash differ from the amount of power demanded by our customers flows from forecasted sales of electricity and purchases of fuel under fixed-price load-serving contracts. During periods of high and energy, including:
demand, our power supplies may be insufficient to serve our
- forward contracts, which commit us to purchase or sell customers' needs and could require us to purchase additional energy commodities in the future; energy at higher prices. Alternatively, during periods of low
- futures contracts, which are cxchange-traded demand, our power supplies may exceed our customers' needs standardized commitments to purchase or sell a and could result in us selling that excess energy at lower prices. commodity or financial instrument, or to make a cash Either of those circumstances could have a negative impact on settlement, at a specific price and future date; our financial results.
- swap agreements, which require payments to or from We are also exposed to variations in the prices and required counterparties based upon the differential between two volumes of natural gas and coal we burn at our power plants to prices for a predetermined contractual (notional) generate electricity. During periods of high demand on our quantity, and generation assets, our fuel supplies may be insufficient and could
- option contracts, which convey the right to buy or sell a require us to procure additional fuel at higher prices. commodity, financial instrument, or index at a Alternatively, during periods of low demand on our generation predetermined price.
assets, our fuel supplies may exceed our needs, and could result The objectives for entering into such hedges indude:
in us selling the excess fuels at lower prices. Either of these
- fixing the price for a portion of anticipated future circumstances will have a negative impact on our financial electricity sales at a level that provides an acceptable results. return on our electric generation operations,
- fixing the price of a portion of anticipated fuel Operations Risk purchases for the operation of our power plants, Operations risk is the risk that a generating plant will not be
- fixing the price for a portion of anticipated energy available to produce energy and the risks related to physical purchases to supply our load-serving customers, and delivery of energy to meet our customers' needs. For 2005, we
- managing our exposure to interest rate risk and foreign expect to use the majority of the generating capacity controlled currency exchange risks.
by our merchant energy business to provide standard offer The portion of forecasted transactions hedged may vary service to BGE or to serve the load requirements of the sellers of based upon management's assessment of market, weather, Nine Mile Point and Ginna. operational, and other factors.
If one or more of our generating facilities is not able to While some of the contracts we use to manage risk produce electricity when required due to operational factors, we represent commodities or instruments for which prices are may have to forego sales opportunities or fulfill fixed-price sales available from external sources, other commodities and certain commitments through the operation of other more costly contracts are not actively traded and are valued using other generating facilities or through the purchase of energy in the pricing sources and modeling techniques to determine expected wholesale market at higher prices. We purchase power from future market prices, contract quantities, or both. We use our generating facilities we do not own. If one or more of those best estimates to determine the fair value of commodity and generating facilities were unable to produce electricity due to derivative contracts we hold and sell. These estimates consider operational factors, we may be forced to purchase electricity in various factors including closing exchange and over-the-counter the wholesale market at higher prices. This could have a material price quotations, time value, volatility factors, and credit adverse impact on our financial results. exposure. However, it is likely that future market prices could Our nuclear plants produce electricity at a relatively low vary from those used in recording mark-to-marker energy assets marginal cost. The Nine Mile Point and Ginna facilities each and liabilities, and such variations could be material.
sell 90% of output under unit-contingent power purchase We measure the sensitivity of our wholesale marketing and agreements (we have no obligation to provide power if the units risk management mark-to-market energy contracts to potential are not available) to the previous owners. However, if an changes in market prices using value at risk. Value at risk is a unplanned outage were to occur at Calvert Cliffs during periods statistical model that attempts to predict risk of loss based on when demand was high, we may have to purchase replacement historical market price volatility. We calculate value at risk using power at potentially higher prices to meet our obligations, which a historical variance/covariance technique that models option could have a material adverse impact on our financial results. positions using a linear approximation of their value.
Additionally, wc estimate variances and correlation using Risk Management historical commodity price changes over the most recent rolling As part of our overall portfolio, we manage the commodity price three-month period. Our value at risk calculation includes all risk of our competitive supply activities and our electric wholesale marketing and risk management mark-to-market generation facilities, including power sales, fuel and energy energy assets and liabilities, including contracts for energy purchases, emission credits, interest rate and foreign currency commodities and derivatives that result in physical settlement risks, weather risk, and the market risk of outages. In order to and contracts that require cash settlement.
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The value at risk calculation does not include market risks Due to the inherent limitations of statistical measures such associated with activities that are subject to accrual accounting, as value at risk and the seasonality of changes in market prices, primarily our generating facilities and our competitive supply the value at risk calculation may not reflect the full extent of load-serving activities. We manage these risks by monitoring our our commodity price risk exposure. Additionally, actual changes fuel and energy purchase requirements and our estimated in the value of options may differ from the value at risk contract sales volumes compared to associated supply calculated using a linear approximation inherent in our arrangements. We also engage in hedging activities to manage calculation method. As a result, actual changes in the fair value these risks. We describe those risks and our hedging activities of mark-to-market energy assets and liabilities could differ from earlier in this section. the calculated value at risk, and such changes could have a The value at risk amounts below represent the potential material impact on our financial results.
pre-tax loss in the fair value of our wholesale marketing and risk management mark-to-market energy assets and liabilities over Regulated Electric Business one and ten-day holding periods. BGE's residential base rates are frozen for a six-year period ending June 30, 2006, and its commercial and industrial base Total WMolesale Value at Risk rates were frozen for a four-year period that ended June 30, For the year ended December 31, 2004 2003 2004. The commodity and transmission components of rates are (In milions) frozen for different time periods depending on the customer 99% Confidence Level, One-Day Holding Period type and service options selected by customers.
Year end $4.4 53.7 Our wholesale marketing and risk management operation Average 3.7 6.6 High 7.8 13.3 provided BGE with 100% of the energy and capacity required Low 2.5 2.7 to meet its commercial and industrial standard offer service obligations through June 30, 2004, and provides 100% of the 95% Confidence Level, One-Day Holding Period energy and capacity to meet its residential standard offer service Year end $ 3.4 $ 2.8 obligations through June 30, 2006. Effective July 1, 2004, BGE Average 2.8 5.0 High 10.1 executed one and two-year contracts for commercial and 5.9 Low 1.9 2.1 industrial electric power supply totaling approximately 2,300 megawatts. Our wholesale marketing and risk management 95% Confidence Level, Ten-Day Holding Period operation will provide a significant portion of this electric power Year end $10.7 $ 8.8 supply.
Average 9.0 15.9 Bidding to supply BGE's standard offer service to High 18.7 32.0 LOW 6.1 6.5 commercial and industrial customers for one, two, or four-year periods beyond June 30, 2004, and to residential customers Based on a 99% confidence interval, we would expect a beyond June 30, 2006, will occur from time to time through a one-day change in the fair value of the portfolio greater than or competitive bidding process approved by the Maryland PSC. We equal to the daily value at risk approximately once in every discuss standard offer service and the impact on base rates in 100 days. In 2004, we experienced four instances where the more detail in Item 1. Business-ElectricBusiness section.
actual daily mark-to-market change in portfolio value exceeded BGE may receive performance assurance collateral from the predicted value at risk. On average, we expect to experience suppliers to mitigate suppliers' credit risks in certain a change in value to our portfolio greater than our value at risk circumstances. Performance assurance collateral is designed to approximately three times in a calendar year. However, published protect BGE's potential exposure over the term of the supply market studies conclude that exceeding daily value at risk less contracts and will fluctuate to reflect changes in market prices.
than seven times in a one-year period is considered consistent In addition to the collateral provisions, there are supplier with a 99% confidence interval. 'step-up" provisions, where other suppliers can step in if the The table above is the value at risk associated with our early termination of a Full-Requirements Service Agreement with wholesale marketing and risk management operation's a supplier should occur, as well as specific mechanisms for BGE mark-to-market energy assets and liabilities, including both to otherwise replace defaulted supplier contracts. All costs trading and non-trading activities. The following table details incurred by BGE to replace the supply contract are to be our value at risk for the trading portion of our wholesale recovered from the defaulting supplier or from customers marketing and risk management mark-to-market energy assets through rates. Finally, BGE's exposure to uncollectible expense and liabilities over a one-day holding period at a 99% or credit risk from customers for the commodity portion of the confidence level for 2004 and 2003: bill iscovered by the administrative fee included in Provider of Last Resort rates.
Wholesale Trading Value at Risk At December 31, 2004 2003 Regulated Gus Business (In millions) Our regulated gas business may enter into gas futures, options, Average $2.6 S 4.6 and swaps to hedge its price risk under our market-based rate High 6.9 10.9 incentive mechanism and our off-system gas sales program. We 56
discuss this further in Note 13. At December 31, 2004 and The reduction in the percentage of counterparties with 2003, our exposure to commodity price risk for our regulated investment grade ratings to 62% in 2004 is primarily due to gas business was not material. continued increased exposure to lower credit quality fuel and power supply counterparties that supply fuel to our power plants Credit Risk and provide power to meet certain customer load-serving We are exposed to credit risk, primarily through our merchant requirements.
energy business. Credit risk is the loss that may result from In addition to the credit ratings provided by the major counterparties' nonperformance. We evaluate the credit risk of credit rating agencies, we utilize internal credit ratings to our wholesale marketing and risk management operation and evaluate the creditworthiness of our wholesale customers, our retail competitive supply activities separately as discussed including those companies that do not have public credit below. ratings. The following table provides the breakdown of the credit quality of our wholesale credit portfolio based on our internal Mholesale Credit Risk credit ratings.
We measure wholesale credit risk as the replacement cost for open energy commodity and derivative transactions (both At December 31, 2004 2003 mark-to-market and accrual) adjusted for amounts owed to or Investment Grade Equivalent 74% 91%
due from counterparties for settled transactions. The replacement Non-Investment Grade 26 9 cost of open positions represents unrealized gains, net of any A portion of our wholesale credit risk is related to unrealized losses, where we have a legally enforceable right of transactions that are recorded in our Consolidated Balance setoff. We monitor and manage the credit risk of our wholesale Sheets. These transactions primarily consist of open positions marketing and risk management operation through credit from our wholesale marketing and risk management operation policies and procedures which include an established credit that are accounted for using mark-to-market accounting, as well approval process, daily monitoring of counterparty credit limits, as amounts owed by wholesale counterparties for transactions the use of credit mitigation measures such as margin, collateral, that settled but have not yet been paid. The following table or prepayment arrangements, and the use of master netting highlights the credit quality and exposures related to these agreements.
activities:
During 2004, we continued to observe declines in the creditworthiness of several major participants in the wholesale Net energy markets. We continue to actively manage the credit Total Number of Exposure of portfolio of our wholesale marketing and risk management Exposure Counterparties Counterparties Before Greater than Greater than operation to attempt to reduce the impact of the general decline Credit Credit Net 10% of Net 10% of Net in the overall credit quality of the energy industry and the Rating Collateral Collateral Exposure Exposure Exposure impact of a potential counterparty default. As of December 31, (DoLlan in millions) 2004 and 2003, the credit portfolio of our wholesale marketing Investment grade S 789 S 53 $ 736 1 $158 and risk management operation had the following public credit Split rating 6 - 6 - -
ratings: Non-investment At December 31. 2004 2003 grade 215 151 64 -
Internally Rating rated-Investment Grade' 62% 75% investment Non-Investment Grade 15 4 grade 225 58 167 -
Not Rated 23 21 Internally rated-1 Includes counterparties with an investment grade rating by at non-least one of the major credit ratingagencies. If split rating exists, investment the lower rating is used. grade 77 33 44 - -
Totsl S1312 $295 $1.017 I $158 Due to the possibility of extreme volatility in the prices of energy commodities and derivatives, the market value of contractual positions with individual counterparties could exceed established credit limits or collateral provided by those counterparties. If such a counterparty were then to fail to perform its obligations under its contract (for example, fail to deliver the electricity our wholesale marketing and risk management operation had contracted for), we could incur a loss that could have a material impact on our financial results.
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Additionally, if a counterparty were to default and we were Foreign Currency Risk to liquidate all contracts with that entity, our credit loss would Our merchant energy business is exposed to the impact of include the loss in value of mark-to-market contracts, the foreign exchange rate fluctuations. This foreign currency risk amount owed for settled transactions, and additional payments, arises from our activities in countries where we transact in if any, that we would have to make to settle unrealized losses on currencies other than the U.S. dollar. In 2004, our exposure to accrual contracts. foreign currency risk was not maecrial. However, we expect our foreign currency exposure to grow due to our Canadian presence Retail Credit Risk and intcrnational coal operations. We manage our exposure to We are exposed to retail credit risk through our competitive foreign currency exchange rate risk using a comprehensive electricity and natural gas supply activities which serve foreign currency hedging program. While we cannot predict commercial and industrial companies. Retail credit risk results currency fluctuations, the impact of foreign currency exchange when customers default on their contractual obligations. This rate risk could be material.
risk represents the loss that may be incurred due to the nonpayment of a customer's accounts receivable balance, as well Equity Price Risk as the loss from the resale of energy previously committed to We arc exposed to price fluctuations in equity markets primarily serve the customer. through our pension plan assets, our nudear decommissioning Retail credit risk is managed through established credit trust funds and trust assets securing certain executive benefits.
policies, monitoring customer exposures, and the use of credit We are required by the NRC to maintain externally funded mitigation measures such as letters of credit or prepayment trusts for the costs of decommissioning our nuclear power arrangements. plants. We discuss our nuclear decommissioning trust funds in Our retail credit portfolio is well diversified with no more detail in Note l.
significant company or industry concentrations. During 2004, A hypothetical 10% decrease in equity prices would result we did not experience a material change in the credit quality of in an approximate $110 million reduction in the fair value of our retail credit portfolio compared to 2003. Retail credit quality our financial investments that are classified as trading or is dependent on the economy and the ability of our customers available-for-sale securities. In 2004, the value of our defined to manage through unfavorable economic cycles and other benefit pension plan assets increased by Si 14 million due to market changes. If the business environment were to be advances in the markets in which plan assets arc invested. We negatively affected by changes in economic or other market describe our financial investments in more detail in Note 4, and conditions, our retail credit risk may be adversely impacted. our pension plans in Note 7.
Item 7A. Quantitative and Qualitative Disclosures about Market Risk The information required by this item with respect to market risk is set forth in Item 7of Part II of this Form 10-K under the heading Market Rirk.
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Item 8. Financial Statements and Supplementary Data I &-~, , iIsSil" FinancialStatements accordance with generally accepted accounting principles in the The management of Constellation Energy Group, Inc. and United States of America.
Baltimore Gas and Electric Company (the "Companies") is The management of Constellation Energy conducted an responsible for the information and representations in the evaluation of the effectiveness of Constellation Energy's internal Companies' financial statements. The Companies prepare the control over financial reporting using the framework in Internal financial statements in accordance with accounting principles Control-Integrated Framework issued by the Committee of generally accepted in the United States of America based upon Sponsoring Organizations of the Treadway Commission available facts and circumstances and management's best (COSO). As noted in the COSO framework, an internal control estimates and judgments of known conditions. system, no matter how well conceived and operated, can provide PricewaterhouseCoopers LLP, an independent registered only reasonable-not absolute-assurance to management and the public accounting firm, has audited the financial statements and Board of Directors regarding achievement of an entity's financial expressed their opinion on them. They performed their audit in reporting objectives. Based upon the evaluation under this accordance with the standards of the Public Company framework, management conduded that Constellation Energy's Accounting Oversight Board (United States). internal control over financial reporting was effective as of The Audit Committee of the Board of Directors, which December 31, 2004.
consists of four independent Directors, meets periodically with PricewaterhouseCoopers LLP. an independent registered management, internal auditors, and PricewaterhouseCoopers LLP public accounting firm, has audited management's assessment of to review the activities of each in discharging their the effectiveness of Constellation Energy's internal control over responsibilities. The internal audit staff and financial reporting at December 31, 2004, as stated in their PricewaterhouseCoopers LLP have free access to the Audit report set forth below.
Committee. As discussed in Item 9A. Controls and vrocedures, the management of Baltimore Gas & Electric Company ("BGE")
Management's Report on Internal Control Over has not assessed the effectiveness of BGE's internal control over FinancialReporting financial reporting on a standalone basis because it is not yet The management of Constellation Energy Group, Inc. required to do so by applicable federal securities laws and
("Constellation Energy"), under the direction of its principal regulations.
executive officer and principal financial officer, is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Exchange Act Rule 13a-15(f).
ZoA. =Shaatuck III E. Follin Smith Constellation Energy's system of internal control over financial reporting is designed to provide reasonable assurance to Chairman of the Board, Executive Vlce-Pr-sident, Pirsidentand ChiefExecutive ChiefFinancialOfficer, and Constellation Energy's management and Board of Directors Officer Chief Administrativez Officer regarding the reliability of financial reporting and the preparation of financial statements for external purposes in I*=Lw I = 1111 ..
- F-qo*A1 1 I To the Board of Directors and Shareholdersof Constellation Energy and the results of their operations and their cash flows for each Group, Inc. of the three years in the period ended December 31, 2004 in We have completed an integrated audit of Constellation Energy conformity with accounting principles generally accepted in the Group, Inc. and Subsidiaries' 2004 consolidated financial United States of America. In addition, in our opinion, the statements and of its internal control over financial reporting as financial statement schedule listed in the index appearing under of December 31, 2004 and audits of its 2003 and 2002 Item 15(a) 2 presents fairly, in all material respects. the consolidated financial statements in accordance with the information set forth therein when read in conjunction with the standards of the Public Company Accounting Oversight Board related consolidated financial statements. These financial (United States). Our opinions, based on our audits, are statements and financial statement schedule are the responsibility presented below. of the Company's management; our responsibility is to express an opinion on these financial statements and financial statement Consolidated financial statements and financial schedule based on our audits. We conducted our audits of these statement schedule statements in accordance with the standards of the Public In our opinion, the consolidated financial statements listed in Company Accounting Oversight Board (United States). Those the index appearing under Item 15(a) 1. present fairly, in all standards require that we plan and perform the audit to obtain material respects, the financial position of Constellation Energy reasonable assurance about whether the financial statements are Group, Inc. and Subsidiaries at December 31, 2004 and 2003, free of material misstatement. An audit of financial statements 59
includes examining, on a test basis, evidence supporting the statements for external purposes in accordance with generally amounts and disclosures in the financial statements, assessing the accepted accounting principles. A company's internal control accounting principles used and significant estimates made by over financial reporting includes those policies and procedures management, and evaluating the overall financial statement that (i) pertain to the maintenance of records that, in reasonable presentation. We believe that our audits provide a reasonable detail, accurately and fairly reflect the transactions and basis for our opinion. dispositions of the assets of the company; (ii) provide reasonable We have also previously audited, in accordance with the assurance that transactions are recorded as necessary to permit standards of the Public Company Accounting Oversight Board preparation of financial statements in accordance with generally (United States), the consolidated balance sheets and statements accepted accounting principles, and that receipts and of capitalization of Constellation Energy Group, Inc. and expenditures of the company are being made only in accordance Subsidiaries as of December 31. 2002, 2001 and 2000, and the with authorizations of management and directors of the related consolidated statements of income, cash flows, and company; and (iii) provide reasonable assurance regarding common shareholders' equity and comprehensive income for the prevention or timely detection of unauthorized acquisition, use, years ended December 31. 2001 and 2000 (none of which are or disposition of the company's assets that could have a material presented herein); and we expressed unqualified opinions on effect on the financial statements.
those consolidated financial statements. In our opinion, the Because of its inherent limitations, internal control over information set forth in the Summary of Operations and financial reporting may not prevent or detect misstatements.
Summary of Financial Condition of Constellation Energy Also, projections of any evaluation of effectiveness to future Group, Inc. and Subsidiaries included in the Selected Financial periods are subject to the risk that controls may become Data for each of the five years in the period ended inadequate because of changes in conditions, or that the degree December 31, 2004, is fairly stated, in all material respects, in of compliance with the policies or procedures may deteriorate.
relation to the consolidated financial statements from which it has been derived.
Internal control over financial reporting PricewaterhouseCoopers LLP Also, in our opinion, management's assessment, included in Atlanta, Georgia Management's Report on Internal Control Over Financial March 10, 2005 Reporting appearing under Item 8, that the Company maintained effective internal control over financial reporting as To Board of Directorsand SharrholderofBaltimore Gas and of December 31, 2004, based on criteria established in Internal Electric Company Control-Integrated Framework issued by the Committee of In our opinion, the consolidated financial statements listed in Sponsoring Organizations of the Treadway Commission the index appearing under Item 15(a) 1. present fairly, in all (COSO), is fairly stated, in all material respects, based on those material respects, the financial position of Baltimore Gas and criteria. Furthermore, in our opinion, the Company maintained, Electric Company and Subsidiaries at December 31, 2004 and in all material respects, effective internal control over financial 2003, and the results of their operations and their cash flows for reporting as of December 31, 2004, based on criteria established each of the three years in the period ended December 31, 2004 in Internal Control-integrated Framework issued by the in conformity with accounting principles generally accepted in COSO. The Companys management is responsible for the United States of America. In addition, in our opinion, the maintaining effective internal control over financial reporting financial statement schedule listed in the index appearing under and for its assessment of the effectiveness of internal control over Item 15(a) 2 presents fairly, in all material respects, the financial reporting. Our responsibility is to express opinions on information set forth therein when read in conjunction with the management's assessment and on the effcaiveness of the related consolidated financial statements. These financial Company's internal control over financial reporting based on our statements are the responsibility of the Company's management; audit. We conducted our audit of internal control over financial our responsibility is to express an opinion on these financial reporting in accordance with the standards of the Public statements based on our audits. We conduced our audits of Company Accounting Oversight Board (United States). Those these statements in accordance with the standards of the Public standards require that we plan and perform the audit to obtain Company Accounting Oversight Board (United States). Those reasonable assurance about whether effective internal control over standards require that we plan and perform the audit to obtain financial reporting was maintained in all material respects. An reasonable assurance about whether the financial statements are audit of internal control over financial reporting includes free of material misstatement. An audit includes examining, on a obtaining an understanding of internal control over financial test basis, evidence supporting the amounts and disclosures in reporting, evaluating management's assessment, testing and the financial statements, assessing the accounting principles used evaluating the design and operating effectiveness of internal and significant estimates made by management, and evaluating control, and performing such other procedures as we consider the overall financial statement presentation. We believe that our necessary in the circumstances. We believe that our audit audits provide a reasonable basis for our opinion.
provides a reasonable basis for our opinions.
We have also previously audited, in accordance with the A company's internal control over financial reporting is a standards of the Public Company Accounting Oversight Board process designed to provide reasonable assurance regarding the (United States), the consolidated balance sheets of Baltimore Gas reliability of financial reporting and the preparation of financial 60
and Electric Company and Subsidiaries as of December 31, period ended December 31, 2004, is fairly stated, in all material 2002, 2001 and 2000, and the related consolidated statements respects, in relation to the consolidated financial statements from of income, cash flows, and common shareholders' equity and which it has been derived.
comprehensive income for the years ended December 31, 2001 and 2000 (none of which are presented herein); and we expressed unqualified opinions on those consolidated financial statements. In our opinion, the information set forth in the PricewaterhouseCoopers LLP Summary of Operations and Summary of Financial Condition of Atlanta, Georgia Baltimore Gas and Electric Company and Subsidiaries included March 10, 2005 in the Selected Financial Data for each of the five years in the 61
Constellation Energy Group, Inc. and Subsidiaries Year Ended December 31, 2004 2003 2002 (In millions, exrept per share amounts)
Revenues Nonregulated revenues $ 9,827.0 $7,053.6 $2,182.5 Regulated electric revenues 1,967.6 1,921.5 1,965.6 Regulated gas revenues 755.1 712.7 570.5 Total revenues 12,549.7 9,687.8 4,718.6 Expenses Fuel and purchased energy expenses 8,849.6 6,297.1 1,709.8 Operating expenses 1,770.7 1,575.6 1,380.8 Workforce reduction costs 9.7 2.1 62.8 Impairment losses and other costs 3.7 0.6 25.2 Depreciation and amortization 525.5 479.0 481.0 Accretion of asset retirement obligations 53.2 42.7 Taxes other than income taxes 258.9 250.6 234.1 Total expenses 11,471.3 8,647.7 3,893.7 Net (Loss) Gain on Sales of Investments and Other Assets (1.2) 26.2 261.3 Income from Operations 1,077.2 1,066.3 1,086.2 Other Income 14.1 19.1 30.5 Fixed Charges Interest expense 328.0 340.8 312.3 Interest capitalized and allowance for borrowed funds used during construction (10.9) (13.8) (44.0)
BGE preference stock dividends 13.2 13.2 13.2 Total fixed charges 330.3 340.2 281.5 Income Before Income Taxes 761.0 745.2 835.2 Income Taxes 172.2 269.5 309.6 Income from Continuing Operations and Before Cumulative Effects of Changes in Accounting Principles 588.8 475.7 525.6 Loss from discontinued operations. net of income taxes of $26.5 (see Note
- 2) (49.1) - -
Cumulative effects of changes in accounting principles, net of income taxes of $119.5 - (198.4) -
Net Income $ 539.7 $ 277.3 $ 525.6 Earnings Applicable to Common Stock $ 539.7 $ 277.3 $ 525.6 Average Shares of Common Stock Outstanding-Basic 172.1 166.3 164.2 Average Shares of Common Stock Outstanding-Diluted 173.1 166.7 164.2 Earnings Per Common Share from Continuing Operations and Before Cumulative Effects of Changes in Accounting Principles-Basic $ 3.42 $ 2.86 $ 3.20 Loss from discontinued operations (0.28)
Cumulative effects of changes in accounting principles - (1.19)
Earnings Per Common Share-Basic $ 3.14 $ 1.67 $ 3.20 Earnings Per Common Share from Continuing Operations and Before Cumulative Effects of Changes in Accounting Principles-Diluted $ 3.40 S 2.85 $ 3.20 Loss from discontinued operations (0.28)
Cumulative effects of changes in accounting principles - (1.19)
Earnings Per Common Share-Diluted $ 3.12 $ 1.66 $ 3.20 Dividends Declared Per Common Share $ 1.14 $ 1.04 $ 0.96 See Notes to ConsolidatedFinancialStatements.
Certain prior-yearamounts have been reclassified to conform with the current years presentation.
62
Constellation Energy Group, Inc. and Subsidiaries At December 31, 2004 2003 (In millions)
Assets Current Assets Cash and cash equivalents $ 7063 $ 721.3 Accounts receivable (net of allowance for uncollectibles of $43.1 and $51.7, respectively) 1,979.3 1,563.0 Mark-to-market energy assets 567.3 504.8 Risk management assets 471.5 233.0 Materials and supplies 203.8 203.2 Fuel stocks 298.3 196.8 Other 262.9 220.3 Total current assets 4,489.4 3,642.4 Investments and Other Assets Nuclear decommissioning trust funds 1,033.7 736.1 Investments in qualifying facilities and power projects 318.4 332.6 Mark-to-market energy assets 359.8 265.8 Risk management assets 306.2 154.5 Regulatory assets (net) 195.4 229.5 Goodwill 144.8 146.3 Other 412.8 484.3 Total investments and other assets 2,771.1 2,349.1 Property, Plant and Equipment Regulated property, plant and equipment Plant in service 5,324.4 5,131.7 Construction work in progress 83.1 130.5 Plant held for future use 5.2 4.5 Total regulated property, plant and equipment 5,412.7 5,266.7 Nonregulated property, plant and equipment 8,638.4 8,110.0 Nuclear fuel (net of amnorizarion) 2643 202.9 Accumulated depreciation (4,228.8) (3,978.1)
Net property, plant and equipment 10,086.6 9,601.5 Total Assets $17,347.1 $15,593.0 See Notes to ConsolidatedFinancialStatements.
Certain prior-year amounts have been reclassified to conform with the current years presentation.
63
] ;441 I;*. I A.; iA.E1I Constellation Energy Group, Inc. and Subsidiaries At December 31, 2004 2003 (In millions)
Liabilities and Equity Current Liabilities Short-term borrowings $ - $ 9.6 Current portion of long-term debt 480.4 343.2 Accounts payable and accrued liabilities 1,424.9 1,142.0 Customer deposits and collateral 223.8 194.5 Mark-to-marker energy liabilities 559.7 490.4 Risk management liabilities 304.3 118.8 Accrued expenses and other 6693 628.9 Total current liabilities 3,662.4 2,927.4 Deferred Credits and Other Liabilities Deferred income taxes 1,303.3 1,311.8 Asset retirement obligations 825.0 595.9 Mark-to-market energy liabilities 315.0 261.4 Risk management liabilities 472.2 166.7 Postretirement and postemployment benefits 375.3 361.8 Net pension liability 269.7 225.7 Deferred investment tax credits 712 78.4 Other 232.0 180.8 Total deferred credits and other liabilities 3,863.7 3,182.5 Capitalization (See Consolidated Statements of Capitalization)
Long-term debt 4,813.2 5,039.2 Minority interests 90.9 113.4 BGE preference stock not subject to mandatory redemption 190.0 190.0 Common shareholders' equity 4,726.9 4,140.5 Total capitalization 9,821.0 9,483.1 Commitments, Guarantees, and Contingencies (see Note 12)
Total Liabilities and Equity $17,347.1 $15,593.0 See Notes to ConsolidatedFinancialStatements.
Certainprior-year amounts have been reclassifiedto conform with the currentyearlpresentation.
64
.; , l Constellation Energy Group, Inc. and Subsidiaries Year Ended December 31, 2004 2003 2002 (In millions)
Cash Flows From Operating Activities Net income $ 539.7 S 277.3 $ 525.6 Adjustments to reconcile to net cash provided by operatinig activities Loss from discontinued operations 49.1 - -
Cumulative effects of changes in accounting principles - 198.4 Depreciation and amortization 660.7 611.7 558.0 Accretion of asset retirement obligations 53.2 42.7 Deferred income taxes 123.4 109.2 148.3 Investment tax credit adjustments (7.2) (7.3) (7.9)
Deferred fuel costs 6.0 (10.1) 23.9 Pension and postemployment benefits (3-0) (69.4) (116.2)
Net loss (gain) on sales of investments and other assets 1.2 (26.2) (261.3)
Workforce reduction costs 9.7 2.1 62.8 Impairment losses and other costs 3.7 0.6 25.2 Equity in earnings of affiliates less than dividends received 30.5 38.4 67.0 Changes in Accounts receivable (437.4) (291.0) (236.8)
Mark-to-market energy assets and liabilities (26.1) 29.9 (133.7)
Risk management assets and liabilities 5.3 (83.5) 58.6 Materials, supplies, and fuel stocks (112.1) (51.5) (11.7)
Other current assets 2.4 19.3 130.3 Accounts payable and accrued liabilities 273.9 204.1 188.4 Other current liabilities (35.6) 107.4 53.9 Other (50.6) (44.3) (68.6)
Net cash provided by operating activities 1,086.8 1,057.8 1,005.8 Cash Flows From Investing Activities Investments in property, plant and equipment (703.6) (635.7) (817.7)
Acquisitions. net of cash acquired (457.3) (546.6) (221.4)
Contributions to nudear decommissioning trust funds (22.0) (13.2) (17.6)
Net proceeds from sale of discontinued operations 72.7 -
Sale of investments and other assets 36.1 148.8 838.0 Other investments (78.6) (113.6) (86.9)
Net cash used in investing activities (1,152.7) (1,160.3) (305.6)
Cash Flows From Financing Activities Net maturity of short-term borrowings (9.6) (0.9) (964.5)
Proceeds from issuance of Common stock 293.9 95.4 28.5 Long-term debt 100.0 983.3 2,529.3 Repayment of long-term debt (243.2) (707.5) (1,627.7)
Common stock dividends paid (189.7) (169.2) (137.8)
Proceeds from acquired contracts 117.5 -
Other (18.0) 7.7 14.6 Net cash provided by (used in) financing activities 50.9 208.8 (157.6)
Net (Decrease) Increase in Cash and Cash Equivalents (15.0) 106.3 542.6 Cash and Cash Equivalents at Beginning of Year 721.3 615.0 72.4 Cash and Cash Equivalents at End of Year $ 706.3 $ 721.3 $ 615.0 Other Cash Flow Information:
Cash paid during the year for:
Interest (net of amounts capitalized) $ 331.4 $ 339.4 $ 230.5 Income taxes $ 207.9 $ 34.0 $ 157.8 See Notes to ConsolidatedFinancialStatements.
Certainprior-year amounts have been nrecLssified to conform with the current year's presentation.
65
Constellation Energy Group, Inc. and Subsidiaries Accumulated Other Common Stock Retained Comprehensive Total Year Ended December 31. 2004. 2003. and 2002 Shares Amount Earnings Income (Loss) Amount (Dollar amounts in millions. number of shares in thousands)
Balance at December 31, 2001 163,708 $2,042.2 $ 1,611.5 $ 189.9 $3,843.6 Comprehensive Income Net income 525.6 525.6 Other comprehensive income (OCI)
Redassification of net gain on sales of securities from OCI to net income, net of taxes of $87.7 (152.8) (152.8)
Redassification of net gain on hedging instruments from OCI to net income, net of taxes of $10.9 (17.8) (17.8)
Net unrealized loss on securities, net of taxes of $28.6 (43.2) (43.2)
Net unrealized loss on hedging instruments, net of taxes of $31.7 (52.2) (52.2)
Minimum pension liability, net of taxes of $77.2 (118.1) (118.1)
Total Comprehensive Income 525.6 (384.1) 141.5 Common stock dividend declared ($0.96 per share) (157.6) (157.6)
Common stock issued 1,135 28.5 28.5 Other 8.2 (1-9) 6.3 Balance at December 31, 2002 164,843 2,078.9 1,977.6 (194.2) 3,862.3 Comprehensive Income Net income 277.3 277.3 Other comprehensive income Reclassification of net gain on sales of securities from OCI to net income, net of taxes of $0.2 (0.4) (0.4)
Reclassification of net gains on hedging instruments from OCI to net income, net of taxes of $10.7 (16.4) (16.4)
Net unrealized gain on securities, net of taxes of $24.4 37.3 37.3 Net unrealized gain on hedging instruments, net of taxes of $15.8 39.9 39.9 Minimum pension liability, net of taxes of $8.2 12.6 12.6 Total Comprehensive Income 277.3 73.0 350.3 Common stock dividend declared ($1.04 per share) (172.8) (172.8)
Common stock issued 2,976 100.9 100.9 Other (0.2) (0.2)
Balance at December 31, 2003 167,819 2,179.8 2,081.9 (121.2) 4,140.5 Comprehensive Income Net income 539.7 539.7 Other comprehensive income Redassification of net loss on securities from OCI to net income, net of taxes of $1.4 2.2 2.2 Reclassification of net gains on hedging instruments from OCI to net income, net of taxes of $169.0 (270.8) (270.8)
Net unrealized gain on securities, net of taxes of $22.2 33.7 33.7 Net unrealized gain on hedging instruments, net of taxes of $124.7 196.8 196.8 Net unrealized gain on foreign currency translation 0.4 0.4 Minimum pension liability, net of taxes of $27.9 (42.6) (42.6)
Total Comprehensive Income 539.7 (80.3) 459.4 Common stock dividend declared ($1.14 per share) (196.3) (196.3)
Common stock issued 8,514 322.7 322.7 Other 0.6 0.6 Balance at December 31, 2004 176,333 $2,502.5 $2,425.9 $(201.5) $4,726.9 See Notes to Consolidated Financial Statements.
66
Constellation Energy Group, Inc. and Subsidiaries At December 31, 2004 2003 (In millions)
Long-Term Debt Long-term debt of Constellation Energy 73/8% Notes, due April 1, 2005 $ 300.0 $ 300.0 6.35% Fixed-Ratc Notes, due April 1, 2007 600.0 600.0 6.125% Fixed-Ratc Notes, due September 1, 2009 500.0 500.0 7.00% Fixed-Ratc Notes, due April 1, 2012 700.0 700.0 4.55% Fixed-Rate Notes, due June 15, 2015 550.0 550.0 7.60% Fixed-Rate Notes, due April 1, 2032 700.0 700.0 Fair Value of Interest Rate Swaps 13.3 -
Total long-term debt of Constellation Energy 3,363.3 3,350.0 Long-term debt of nonregulated businesses Tax-exempt debt transferred from BGE ceffcctive July 1, 2000 Pollution control loan, due July 1, 2011 36.0 36.0 Port facilities loan, due June 1, 2013 48.0 48.0 Adjustable rate pollution control loan, due July 1, 2014 20.0 20.0 5.55% Pollution control revenue refunding loan, due July 15, 2014 47.0 47.0 Economic development loan, due December 1, 2018 35.0 35.0 6.00% Pollution control revenue refunding loan, due April 1, 2024 75.0 75.0 Floating-rate pollution control loan, due June 1, 2027 8.8 8.8 District Cooling facilities loan, due December 1, 2031 25.0 25.0 Loans under revolving credit agreements 100.1 46.3 Geothermal facilities loan, due Septembcr 30, 2011 45.3 4.25% Mortgagc note, due March 15, 2009 2.3 2.8 South Carolina synthetic fuel facility loan, due January 15, 2008 40.0 Total long-term debt of nonregulated businesses 437.2 389.2 First Refunding Mortgage Bonds of BGE 5'h% Series, due April 15, 2004 125.0 Remarketed floating-rate series, due September 1, 2006 99.3 104.1 7!6% Series, due January 15, 2007 122.5 122.5 6'/s% Series, due March 15, 2008 124.5 124.5 Total First Refunding Mortgage Bonds of BGE 346.3 476.1 Other long-term debt of BGE 5.25% Notes, due December 15, 2006 300.0 300.0 5.20% Notes, due June 15, 2033 200.0 200.0 Medium-tcrm notes, Series B 12.1 12.1 Medium-term notes, Series D 48.0 68.0 Medium-term notes, Series E 199.5 199.5 Medium-term notes, Series G 140.0 140.0 Total other long-term debt of BGE 899.6 919.6 6.20% deferrable interest subordinated debentures due October 15, 2043 to BGE wholly owned BGE Capital Trust II relating to trust preferred securities 257.7 257.7 Unamortized discount and premium (10.5) (10.2)
Current portion of long-term debt (480.4) (343.2)
Total long-term debt $4,813.2 $5,039.2 See Notes to ConsolidatedFinancialStatements.
continued on next page 67
Constellation Energy Group, Inc. and Subsidiaries At December 31, 2004 2003 (In millions)
Minority Interests $ 90.9 $ 113.4 BGE Preference Stock Cumulative preference stock not subject to mandatory redemption, 6,500,000 shares authorized 7.125%, 1993 Series, 400,000 shares outstanding, callable at $103.21 per share until June 30, 2005, and at lesser amounts thereafter 40.0 40.0 6.97%, 1993 Series, 500,000 shares outstanding, callable at $103.14 per share until September 30, 2005, and at lesser amounts thereafter 50.0 50.0 6.70%, 1993 Series, 400,000 shares outstanding, callable at $103.02 per share until December 31, 2005, and at lesser amounts thereafter 40.0 40.0 6.99%, 1995 Series, 600,000 shares outstanding, not callable prior to October 1, 2005, then callable at $103.50 per share until September 30, 2006 60.0 60.0 Total preference stock not subject to mandatory redemption 190.0 190.0 Common Shareholders' Equity Common stock without par value, 250,000,000 shares authorized; 176,333,121 and 167,819,338 shares issued and outstanding at December 31, 2004 and 2003, respectively.
(At December 31, 2004, 5,884,607 shares were reserved for the long-term incentive plans, 7,957,620 shares were reserved for the Shareholder Investment Plan, 520,000 shares were reserved for the continuous offering programs, and 422,651 shares were reserved for the employee savings plan.) 2,502.5 2,179.8 Retained earnings 2,425.9 2,081.9 Accumulated other comprehensive loss (201.5) (121.2)
Total common shareholders' equity 4,726.9 4,140.5 Total Capitalization $9,821.0 $9,483.1 See Notes to ConsolidatedFinancialStatements.
68
- E. Auks. .= I A Baltimore Gas and Electric Company and Subsidiaries Year Ended December 31, 2004 2003 2002 (In millions)
Revenues Electric revenues $1,967.7 $1,921.6 $1,966.0 Gas revenues 757.0 726.0 581.3 Total revenues 2,724.7 2,647.6 2,547.3 Expenses Operating Expenses Electricity purchased for resale expenses 1,034.0 1,023.5 1,080.7 Gas purchased for resale 484.3 445.8 316.7 Operations and maintenance 427.8 406.2 366.6 Workforce reduction costs - 0.7 35.3 Depreciation and amortization 242.3 228.3 221.6 Taxes other than income taxes 164.9 158.1 160.1 Total expenses 2,353.3 2,262.6 2,181.0 Income from Operations 371.4 385.0 366.3 Other (Expense) Income (6.4) (5.4) 10.7 Fixed Charges Interest expense 97.3 112.8 142.1 Allowance for borrowed funds used during construction (1.1) (1.6) (1.5)
Total fixed charges 96.2 111.2 140.6 Income Before Income Taxes 268.8 268.4 236.4 Income Taxes Current 69.4 48.5 67.4 Deferred 34.9 58.5 28.0 Investment tax credit adjustments (1.8) (1.8) (2.1)
Total income taxes 102.5 105.2 93.3 Net Income 166.3 163.2 143.1 Preference Stock Dividends 13.2 13.2 13.2 Earnings Applicable to Common Stock $ 153.1 $ 150.0 $ 129.9 U
Baltimore Gas and Electric Company and Subsidiaries Year Ended December 31. 2004 2003 2002 (in millions)
Net Income $ 153.1 $ 150.0 $ 129.9 Other comprehensive income Reclassification of net gains on hedging instruments from OCI to net income, net of taxes of $0.0 (0.1) - _
Unrealized gain on hedging instruments, net of taxes of $0.4 - 0.8 Comprehensive Income $ 153.0 $ 150.8 $ 129.9 See Notes to ConsolidatedFinancialStatements Certainprior-year amounts have been reclassifiedto conform with the current years presentation.
69
Baltimore Gas and Electric Company and Subsidiaries At December.31. 2004 2003 (In millions)
Assets Current Assets Cash and cash equivalents $ 8.2 $ 11.0 Accounts receivable (net of allowance for uncollectibles of $13.0 and $10.7, respectively) 381.8 354.8 Investment in cash pool, affiliated company 127.9 230.2 Accounts receivable, affiliated companies 1.0 4.5 Fuel stocks 86.5 62.8 Materials and supplies 34.6 29.9 Prepaid taxes other than income taxes 44.5 42.8 Other 7.2 9.9 Total current assets 691.7 745.9 Investments and Other Assets Regulatory assets (net) 195.4 229.5 Receivable, affiliated company 150.4 131.6 Other 134.2 140.6 Total investments and other assets 480.0 501.7 Utility Plant Plant in service Electric 3,759.3 3,599.3 Gas 1,086.7 1,064.7 Common 478.4 467.7 Total plant in service 5,324.4 5,131.7 Accumulated depreciation (1,921.5) (1,807.7)
Net plant in service 3,402.9 3,324.0 Construction work in progress 83.1 130.5 Plant held for future use 5.2 4.5 Net utility plant 3,491.2 3,459.0 Total Assets $ 4,662.9 S 4,706.6 See Notes to ConsolidatedFinancialStatements.
Certain prior-yearamounts have been reclassified to conform with the currentyearspresentation.
70
- 6 S i,6.1 -L o .
Baltimore Gas and Electric Company and Subsidiaries At December 31) 2004 2003 (In millions)
Liabilities and Equity Current Liabilities Current portion of long-term debt $ 165.9 $ 330.6 Accounts payable and accrued liabilities 125.4 101.2 Accounts payable and accrued liabilities, affiliated companies 146.1 151.7 Customer deposits 64.3 59.7 Accrued taxes 32.2 43.0 Accrued expenses and other 71.7 75.2 Total current liabilities 605.6 761.4 Deferred Credits and Other liabilities Deferred income taxes 608.0 576.2 Postretirement and postemployment benefits 278.2 279.2 Deferred investment tax credits 16.9 18.7 Other 20.0 30.8 Total deferred credits and other liabilities 923.1 904.9 Long-term Debt First refunding mortgage bonds of BGE 346.3 476.1 Other long-term debt of BGE 899.6 919.6 6.20% deferrable interest subordinated debentures due October 15, 2043 to wholly owned BGE Capital Trust 11 relating to trust preferred securities 257.7 257.7 Long-term debt of nonregulated businesses 25.0 25.0 Unamortized discount and premium (3.2) (4.1)
Current portion of long-term debt (165.9) (330.6)
Total long-term debt 1,359.5 1,343.7 Minority Interest 18.7 18.9 Preference Stock Not Subject to Mandatory Redemption 190.0 190.0 Common Shareholder's Equity Common stock 912.2 912.2 Retained earnings 653.1 574.7 Accumulated other comprehensive income 0.7 0.8 Total common shareholder's equity 1,566.0 1,487.7 Commitments, Guarantees, and Contingencies (see Note 12)
Total liabilities and Equity $ 4,662.9 $ 4,706.6 See Nlotes to ConsolidatedFinancialStatements.
Certain prior-year amounts have been reclassified to conftrm with the currentyearspresentation.
71
Baltimore Gas and Electric Company and Subsidiaries Year Ended December 31, 2004 2003 2002 (In millions)
Cash Flows From Operating Activities Net income $ 166.3 S 163.2 $ 143.1 Adjustments to reconcile to net cash provided by operating activities Depreciation and amortization 257.4 242.7 234.4 Deferred income taxes 34.9 58.5 28.0 Investment tax credit adjustments (1.8) (1.8) (2.1)
Deferred fuel costs 6.0 (10.1) 23.9 Pension and postemployment benefits (16.6) (56.2) (40.7)
Allowance for equity funds used during construction (2.0) (3.0) (2.8)
Workforce reduction costs 0.7 35.3 Changes in Accounts receivable (27.0) 2.7 (62.3)
Receivables, affiliated companies 3.5 126.7 (67.8)
Materials, supplies, and fuel stocks (28.4) (20.3) 13.0 Other current assets 1.0 (0.4) 27.8 Accounts payable and accrued liabilities 24.2 8.0 39.6 Accounts payable and accrued liabilities, affiliated companies (5.6) 66.1 (7.0)
Other current liabilities (10.3) 14.0 (11.2)
Other (30.2) (22.9) 129.0 Net cash provided by operating activities 371.4 567.9 480.2 Cash Flows From Investing Activities Utility construction expenditures (exduding equity portion of allowance for funds used during construction) (246.4) (269.0) (202.5)
Change in cash pool at parent 102.3 107.9 101.0 Sales of investments and other assets 4.9 -
Other 2.7 1.8 (17.0)
Net cash used in investing activities (136.5) (159.3) (118.5)
Cash Flows From Financing Activities Proceeds from issuance of long-term debt - 439.4 Repayment of long-term debt (149.8) (710.4) (575.5)
Preference stock dividends paid (13.2) (13.2) (13.2)
Distribution (to) from parent (74.7) (124.8) 200.0 Other - 1.2 (0.2)
Net cash used in financing activities (237.7) (407.8) (388.9)
Net (Decrease) Increase in Cash and Cash Equivalents (2.8) 0.8 (27.2)
Cash and Cash Equivalents at Beginning of Year 11.0 10.2 37.4 Cash and Cash Equivalents at End of Year $ 8.2 $ 11.0 $ 10.2 Other Cash Flow Information:
Cash paid during the year for:
Interest (net of amounts capitalized) $ 95.5 $ 120.6 $ 147.5 Income taxes $ 80.7 $ 24.7 $ 36.6 See Notes to ConsolidatedFinancialStatements.
Certain prior-yearamounts have been reclassified to conform with the currentyearlpresentation.
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I~ ElirliiiiM.di TRr-, ^1f RT llS M iiiiP I Significant Accounting Policies Nature of Our Business The only time we do not use this method is if we can Constellation Energy Group, Inc. (Constellation Energy) is a exercise control over the operations and policies of the company.
North American energy company that conducts its business If we have control, accounting rules require us to use through various subsidiaries including a merchant energy consolidation.
business and Baltimore Gas and Electric Company (BGE). Our merchant energy business is a competitive provider of energy The Cost Method solutions for a variety of customers. BGE is a regulated electric We usually use the cost method if we hold less than a 20%
transmission and distribution utility company and a regulated voting interest in an investment. Under the cost method, we gas distribution utility company with a service territory that report our investment at cost in our Consolidated Balance covers the City of Baltimore and all or part of ten counties in Sheets. The only time we do not use this method is when we central Maryland. We describe our operating segments in Note 3. can exercise significant influence over the operations and policies This report is a combined report of Constellation Energy of the company. If we have significant influence, accounting and BGE. References in this report to 'we" and "our" are to rules require us to use the equity method.
Constellation Energy and its subsidiaries. References in this report to the "regulated business(es)" are to BGE. Regulation of Electric and Gas Business The Maryland Public Service Commission (Maryland PSC) and Consolidation Policy the Federal Energy Regulatory Commission (FERC) provide the We use three different accounting methods to report our final determination of the rates we charge our customers for our investments in our subsidiaries or other companies: regulated businesses. Generally, we use the same accounting consolidation, the equity method, and the cost method. policies and practices used by nonregulated companies for financial reporting under accounting principles generally Consolidation accepted in the United States of America. However, sometimes We use consolidation for two types of entities: the Maryland PSC or the FERC orders an accounting treatment
- subsidiaries (other than variable interest entities) in different from that used by nonregulated companies to which we own a majority of the voting stock, and determine the rates we charge our customers.
- variable interest entities (VIEs) for which we are the When this happens, we must defer (include as an asset or primary beneficiary. Financial Accounting Standards liability in our Consolidated Balance Sheets and exdude from Board (FASB) Interpretation No. (FIN) 46R, our Consolidated Statements of Income) certain regulated Consolidation of Variable Interest Entities, requires us to business expenses and income as regulatory assets and liabilities.
use consolidation when we are the primary beneficiary We have recorded these regulatory assets and liabilities in our of a VIE, which means that we have a controlling Consolidated Balance Sheets in accordance with Statement of financial interest in a VIE. We discuss FIN 46R in Financial Accounting Standards (SFAS) No. 71, Accountingfor more detail later in this Note. the Effects of Certain Types of Regulation.
Consolidation means that we combine the accounts of these We summarize and discuss our regulatory assets and entities with our accounts. Therefore, our consolidated financial liabilities further in Note 6.
statements include our accounts, the accounts of our majority-owned subsidiaries that are not VIEs, and the accounts of VlEs Use of Accounting Estimates for which we are the primary beneficiary. We have not Management makes estimates and assumptions when preparing consolidated any entities for which we do not have a controlling financial statements under accounting principles generally voting interest. WVe eliminate all intercompany balances and accepted in the United States of America. These estimates and transactions when we consolidate these accounts. assumptions affect various matters, including:
- our reported amounts of revenues and expenses in our The Equity Method Consolidated Statements of Income during the reporting We usually use the equity method to report investments, periods, corporate joint ventures, partnerships, and affiliated companies
- our reported amounts of assets and liabilities in our (including qualifying facilities and power projects) where we Consolidated Balance Sheets at the dates of the financial hold a 20% to 50% voting interest. Under the equity method, statements, and we report:
- our disclosure of contingent assets and liabilities at the
- our interest in the entity as an investment in our dates of the financial statements.
Consolidated Balance Sheets, and These estimates involve judgments with respect to
- our percentage share of the earnings from the entity in numerous factors that are difficult to predict and are beyond our Consolidated Statements of Income. management's control. As a result, actual amounts could materially differ from these estimates.
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Reclassifications We record valuation adjustments to reflect uncertainties We have reclassified certain prior-year amounts for comparative associated with certain estimates inherent in the determination purposes. These reclassifications did not affect consolidated net of the fair value of mark-to-markct energy assets and liabilities.
income for the years presented. To the extent possible, we utilize market-based data together with quantitative methods for both measuring the uncertainties Revenues for which we record valuation adjustments and determining the NonregulatedBusinesses level of such adjustments and changes in those levels.
We record revenues from the sale of energy, energy-related We describe below the main types of valuation adjustments products, and energy services under the accrual method of we record and the process for establishing each. Generally, accounting in the period when we deliver energy commodities or increases in valuation adjustments reduce our earnings, and products, render services, or settle contracts. WVe use accrual decreases in valuation adjustments increase our earnings.
accounting for our merchant energy and other nonregulated However, all or a portion of the effect on earnings of changes in business transactions, including the generation or purchase and valuation adjustments may be offset by changes in the value of sale of electricity, gas, and coal as part of our physical delivery the underlying positions.
activities and for power, gas, and coal sales contracts that are not
- Close-out adjustment-represents the estimated cost to subject to mark-to-market accounting. Sales contracts that are dose out or sell to a third-party open mark-to-market eligible for accrual accounting include non-derivativc transactions positions. This valuation adjustment has the effect of and derivatives that qualify for and are designated as normal valuing "long" positions (the purchase of a commodity) purchases and normal sales of commodities that will be at the bid price and "short" positions (the sale of a physically delivered. We record accrual revenues, including commodity) at the offer price. We compute this settlements with independent system operators, on a gross basis adjustment based on our estimate of the bid/offer spread because we are a principal to the transaction and otherwise meet for each commodity and option price and the absolute the requirements of Emerging Issues Task Force (EITF) 03-11, quantity of our net open positions for each year. The Reporting Gains and Losses on Derivative Instruments That Are level of total dose-out valuation adjustments increases as Subject to FASB Statement No. 133, Accountingfor Derivative we have larger unhedged positions, bid-offer spreads Instruments and Hedging Activities, and Not Heldfor Trading increase, or market information is not available, and it Purposes, and EITF 99-19, Reporting Revenue Gross as a Principal decreases as we reduce our unhedged positions, bid-offer versus Net as an Agent. spreads decrease, or market information becomes We may make or receive cash payments at the time we available. To the extent that we are not able to obtain assume a power sale agreement for which the contract price observable market information for similar contracts, the differs from current market prices. We recognize the cash dose-out adjustment is equivalent to the initial contract payment at inception in our Consolidated Balance Sheets as an margin, thereby recording no gain or loss at inception.
In the absence of observable market information, there "Other current asset or liability" to the extent that performance is a presumption that the transaction price is equal to under the contract is less than 12 months and as an "Other the market value of the contract, and therefore we do asset or liability" to the extent that performance under the not recognize a gain or loss at inception. We recognize contract is greater than 12 months. We amortize these assets and such gains or losses in earnings as we realize cash flows liabilities into revenues based on the expected cash flows under the contract or when observable market data provided by the contracts.
becomes available.
We record revenues using the mark-to-market method of
- Credit-spread adjustment-for risk management accounting for derivative contracts for which we are not purposes we compute the value of our mark-to-market permitted to use accrual accounting or hedge accounting. We energy assets and liabilities using a risk-free discount discuss our use of hedge accounting in the Derivatives and rate. In order to compute fair value for financial Hedging Activities section later in this Note. These reporting purposes, we adjust the value of our mark-to-market activities include derivative contracts for energy mark-to-marker energy assets to reflect the credit-and other energy-related commodities. Under the worthiness of each customer (counterparty) based upon mark-to-market method of accounting, we record the fair value either published credit ratings, where available, or of these derivatives as mark-to-market energy assets and liabilities equivalent internal credit ratings and associated default at the time of contract execution. We record the changes in probability percentages. We compute this adjustment by mark-to-market energy assets and liabilities on a net basis in applying the appropriate default probability percentage "Nonregulated revenues" in our Consolidated Statements of to our outstanding credit exposure, net of collateral, for Income. Mark-to-market revenues include: each counterparty. The level of this adjustment increases
- gains or losses on new transactions at origination to the as our credit exposure to counterparties increases, the extent permitted by applicable accounting rules, maturity terms of our transactions increase, or the credit
- unrealized gains and losses from changes in the fair ratings of our counterparties deteriorate, and it decreases value of open contracts, when our credit exposure to counterparties decreases,
- net gains and losses from realized transactions, and the maturity terms of our transactions decrease, or the
- changes in valuation adjustments. credit ratings of our counterparties improve.
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Mark-to-market energy assets and liabilities consist of These costs are included in "Fuel and purchased energy derivative contracts. While some of these contracts represent expenses" in our Consolidated Statements of Income. We discuss commodities or instruments for which prices are available from certain of these separately below. We also include certain external sources. other commodities and certain contracts are not non-fuel direct costs, such as ancillary services, transmission actively traded and are valued using modeling techniques to costs, and brokerage fees in "Fuel and purchased energy determine expected future market prices, contract quantities, or expenses" in our Consolidated Statements of Income.
both. The market prices and quantities used to determine fair value reflect management's best estimate considering various Fuel Used to Generate Electriciy and Purhases ofElectricity factors, including closing exchange and over-the-counter From Others quotations, time value, and volatility factors. However, future We assemble a variety of power supply resources, induding market prices and actual quantities will vary from those used in baseload, intermediate, and peaking plants that we own, as well recording mark-to-market energy assets and liabilities, and it is as a variety of power supply contracts that may have similar possible that such variations could be material. characteristics, in order to enable us to meet our customers' During 2002, the FASB issued EITF 02-3, 1ssues Involved energy requirements, which vary on an hourly basis. We in Accounting fr Derivative Contracts Heldfir TradingPurposes purchase power when our load-serving requirements exceed the and Contracts Involved in Energy Trading and Risk Management amount of power available from our supply resources or when it Activities, that changed the accounting for energy contracts. is more economic to do so than to operate our power plants.
These changes included requiring the accrual method of The amount of power purchased depends on a number of accounting for energy contracts that are not derivatives and factors, induding the capacity and availability of our power clarifying when gains or losses can be recognized at the plants, the level of customer demand, and the relative economics inception of derivative contracts. This change applied of generating power versus purchasing power from the spot immediately to new contracts executed after October 25, 2002 market.
and applied to existing non-derivative energy-related contracts We also have acquired contracts and certain power purchase beginning January 1, 2003. agreements that qualify as operating leases. Under these In the first quarter of 2003, we adopted EITF 02-3 and operating leases, we are required to make fixed capacity recognized a $430.0 million pre-tax, or $266.1 million after-tax, payments, as well as variable payments based on the actual charge as a cumulative effect of change in accounting principle. output of the plants. We may make or receive cash payments at The contracts that were subject to the requirements of the time we acquire a contract or assume a power purchase EITF 02-3 were primarily our full requirements load-serving agreement when the contract price differs from current market contracts and unit-contingent power purchase contracts, which prices. We recognize the cash payment at inception in our are not derivatives. These contracts were entered into prior to Consolidated Balance Sheets as an "Other current asset or our shift to accrual accounting earlier in 2002. liability" to the extent that performance under the contract is Certain transactions entered into under master agreements less than 12 months and as an "Other asset or liability" to the and other arrangements provide our merchant energy business extent that performance under the contract is greater than with a right of setoff in the event of bankruptcy or default by 12 months. We amortize these assets and liabilities into fuel and the counterparty. We report such transactions net in our purchased energy expenses based on the expected cash flows Consolidated Balance Sheets in accordance with FASB provided by the contracts.
Interpretation No. 39, Off etting ofAmounis Related to Certain - BGE purchased from our wholesale marketing and risk Contracts. management operation 100% of the energy and capacity We also include equity in earnings from our investments in required to meet its fixed-price standard offer service obligations qualifying facilities and power projects in "Nonregulated through June 30, 2004. BGE purchases 100% of the energy and revenues" in our Consolidated Statements of Income. capacity required to meet its residential fixed-price standard offer service obligations through June 30, 2006 from our wholesale RegulatedBusiness marketing and risk management operation.
We record regulated revenues when we provide service to BGE is obligated to provide market-based standard offer customers. service to residential customers from July 1, 2006 through May 31, 2010, and for commercial and industrial customers for Fuel and Purchased Energy Expenses one, two, or four year periods beyond June 30, 2004, depending W'e incur costs for: on customer load. The POLR rates charged during these time
- the fuel we use to generate electricity, periods will recover BGE's wholesale power supply costs and
- purchases of electricity from others, and include an administrative fee. The administrative fee includes a
- natural gas and coal that we resell. shareholder return component and an incremental cost component.
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Bidding to supply BGE's standard offer service to SFAS No. 133, Accountingfor Derivative Instruments and commercial and industrial customers beyond June 30, 2004 Hedging Activities, as amended, requires that we recognize at fair occurred through a multi-round competitive bidding process in value all derivatives not qualifying for accrual accounting under 2004. As a result, BGE executed one and two-year contracts for the normal purchase and normal sale exception. We record commercial and industrial electric power supply. derivatives that are designated as hedges in "Risk management assets or liabilities" and derivatives not designated as hedges in Regulated Natural Gas "Mark-to-market energy assets or liabilities" in our Consolidated BGE charges its gas customers for the natural gas they purchase Balance Sheets.
from BGE using "gas cost adjustment clauses" set by the We record changes in the value of derivatives that are not Maryland PSC. Under these clauses, BGE defers the difference designated as cash-flow hedges in earnings during the period of between certain of its actual costs related to the gas commodity change. We record changes in the fair value of derivatives and what it collects from customers under the commodity designated as cash-flow hedges that are effective in offsetting the charge in a given period. BGE either bills or refunds its variability in cash flows of forecasted transactions in other customers the difference in the future. The Maryland PSC comprehensive income until the forecasted transactions occur. At approved a modification of the gas cost adjustment clauses to the time the forecasted transactions occur, we reclassify the provide a marker-based rates incentive mechanism. Under the amounts recorded in other comprehensive income into earnings.
market-based rates incentive mechanism, BGE's actual cost of We record the ineffective portion of changes in the fair value of gas is compared to a market index (a measure of the market derivatives used as cash-flow hedges immediately in earnings.
price of gas in a given period). The difference between BGE's We summarize our cash-flow hedging activities under SFAS actual cost and the market index is shared equally between No. 133 and the income statement classification of amounts shareholders and customers. Effective November 2001, the reclassified from 'Accumulated other comprehensive income Maryland PSC approved an order that modifies certain (loss)" as follows:
provisions of the market-based rates incentive mechanism. These provisions require that BGE secure fixed-price contracts for at Income Statement least 10%, but not more than 20%, of forecasted system supply Risk Derivative Classification requirements for the November through March period. These Interest rate risk Interest rate swaps Interest expense fixed-price contracts are not subject to sharing under the market- associated with based rates incentive mechanism. new debt issuances Derivatives and Hedging ActivitIes We are exposed to market risk, including changes in interest Nonregulated Futures and Nonregulated rates and the impact of market fluctuations in the price and energy sales forward revenues transportation costs of electricity, natural gas, and other contracts commodities as discussed further in Note 13. In order to manage Fuel and purchased Nonregulated fuel Futures and these risks, we use both derivative and non-derivative contracts and energy forward energy expenses that may provide for settlement in cash or by delivery of a contracts purchases commodity, including:
- forward contracts, which commit us to purchase or sell Nonregulated gas Futures and Fuel and purchased energy commodities in the future, purchases for forward energy expenses
- futures contracts, which are exchange-traded resale contracts and standardized commitments to purchase or sell a price and basis commodity or financial instrument, or to make a cash swaps settlement, at a specific price and future date, Regulated gas Price and basis Fuel and purchased
- swap agreements, which require payments to or from purchases for swaps energy expenses counterparties based upon the differential between two resale prices for a predetermined contractual (notional) quantity, and
- option contracts, which convey the right to buy or sell a commodity, financial instrument, or index at a predetermined price.
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We designate certain derivatives as fair value hedges. We Taxes record changes in the fair value of these derivatives and changes We summarize our income taxes in Note 10. Our subsidiary in the fair value of the hedged assets or liabilities in earnings as income taxes are computed on a separate return basis. As you the changes occur. We summarize our fair value hedging read this section, it may be helpful to refer to Note 10.
activities and the income statement classification of changes in the fair value of these hedges and the related hedged items as Income Tax Erpense follows: We have two categories of income tax expense-current and deferred. We describe each of these below:
Income Statement
- current income tax expense consists solely of regular tax Risk Derivative Classification less applicable tax credits, and
+ deferred income tax expense is equal to the changes in Optimize mix of Interest rate swaps Interest expense the net deferred income tax liability, excluding amounts fixed and charged or credited to accumulated other comprehensive floating-rate debt income. Our deferred income tax expense is increased or Value of natural Forward contracts Fuel and purchased reduced for changes to the "Income taxes recoverable gas in storage and price and energy expenses through future rates (net)" regulatory asset (described basis swaps later in this Note) during the year.
We record changes in the fair value of interest rate swaps Tax Credits and the debt being hedged in 'Risk management assets and We have deferred the investment tax credits associated with our liabilities" and "Long-term debt" and changes in the fair value of regulated business and assets previously held by our regulated the gas being hedged and related derivatives in "Fuel stocks" and business in our Consolidated Balance Sheets. The investment tax "Risk management assets and liabilities" in our Consolidated credits are amortized evenly to income over the life of each Balance Sheets. In addition, we record the difference between property. We reduce current income tax expense in our interest on hedged fixed-rate debt and floating-rate swaps in Consolidated Statements of Income for the investment tax "Interest expense" in the periods that the swaps settle. credits and other tax credits associated with our nonregulated businesses.
Credit Risk We have certain investments in facilities that manufacture Credit risk is the loss that may result from counterparty solid synthetic fuel produced from coal as defined under non-performance. We arc exposed to credit risk, primarily Section 29 of the Internal Revenue Code for which we claim tax through our merchant energy business. We use credit policies to credits on our Federal income tax return. We recognize the tax manage our credit risk, including utilizing an established credit benefit of these credits in our Consolidated Statements of approval process, daily monitoring of counterparty limits, Income when we believe it is highly probable that the credits employing credit mitigation measures such as margin, collateral will be sustained.
or prepayment arrangements, and using master netting agreements. We measure credit risk as the replacement cost for DeferredIncome Tax Assets and Liabilities open energy commodity and derivative positions (both We must report some of our revenues and expenses differently mark-to-market and accrual) plus amounts owed from for our financial statements than for income tax return purposes.
countcrpartics for settled transactions. The replacement cost of The tax effects of the temporary differences in these items arc open positions represents unrealized gains, less any unrealized reported as deferred income tax assets or liabilities in our losses where we have a legally enforceable right of setoff. Consolidated Balance Sheets. We measure the deferred income Electric and gas utilities, cooperatives, and energy marketers tax assets and liabilities using income tax rates that are currently comprise the majority of countcrparties underlying our assets in effecr.
from our wholesale marketing and risk management activitics. A portion of our total deferred income tax liability relates We held cash collateral from these counterparties totaling to our regulated business, but has not been reflected in the rates
$145.9 million as of December 31, 2004 and $121.9 million as we charge our customers. We refer to this portion of the liability of December 31, 2003. These amounts are included in as 'Income taxes recoverable through future rates (net)." We
'Customer deposits and collateral" in our Consolidated Balance have recorded that portion of the net liability as a regulatory Sheets. asset in our Consolidated Balance Sheets. We discuss this further in Note 6.
State and Local Taxes State and local income taxes are included in "Income taxes" in our Consolidated Statements of Income.
BGE also pays Maryland public service company franchise tax on distribution, and delivery of electricity and natural gas.
We include the franchise tax in "Taxes other than income taxes" in our Consolidated Statements of Income.
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Earnings Per Share Year Ended December 31, 2004 2003 2002 Basic earnings per common share (EPS) is computed by dividing earnings applicable to common stock by the weighted-average (In millions, except per share number of common shares outstanding for the year. Diluted amounts)
EPS reflects the potential dilution of common stock equivalent Net income, as reported $539.7 $277.3 '$525.6 shares that could occur if securities or other contracts to issue Add: Stock-based compensation common stock were exercised or converted into common stock. determined under intrinsic Our dilutive common stock equivalent shares were 1.0 million value method and included in in 2004 and 0.4 million in 2003 and consisted of stock options. reported net income, net of There were no stock options excluded from the computation of related tax effects 13.2 12.0 6.4 diluted EPS for the year ended December 31, 2004. Stock Deduct: Stock-based options to purchase approximately 1.2 million shares in 2003 compensation expense and approximately 4.1 million shares in 2002 were not dilutive determined under fair value and were excluded from the computation of diluted EPS for based method for all awards, these respective years. net of related tax effects (21.3) (20.7) (17.1)
Pro-forma net income $531.6 $268.6 $514.9 Stock-Based Compensation Under our long-term incentive plans, we have granted stock Earnings per share:
options, performance-based units, performance and service-based Basic-as reported $ 3.14 $ 1.67 $ 3.20 restricted stock, and equity to officers, key employees, and Basic-pro-forma $ 3.09 $ 1.62 $ 3.14 members of the Board of Directors. We discuss this in more Diluted-as reported $ 3.12 $ 1.66 $ 3.20 detail in Note 14. Diluted-pro-forma $ 3.07 $ 1.61 $ 3.13 As permitted by SFAS No. 123, Accountingfir Stock-Based In the table above, the stock-based compensation expense Compensation, we presently measure our stock-based included in reported net income, net of related tax effects is as compensation using the intrinsic value method in accordance follows:
with Accounting Principles Board Opinion (APB) No. 25,
- in 2004, $13.2 million after-tax, or $21.4 million Accountingfor Stock Issued to Employees, and related pre-tax comprised of $1.0 million of pre-tax expense for interpretations. certain stock options, $17.0 million for restricted stock, Our stock options are granted with an exercise price not $2.9 million for performance-based units, and less than the market value of the common stock at the date of $0.5 million for equity grants, grant. Accordingly, no compensation expense is recorded for
- in 2003, $12.0 million after-tax, or $18.6 million these awards. However, when we grant options subject to a pre-tax comprised of $1.8 million of pre-tax expense for contingency, we recognize compensation expense when options certain stock options, $16.4 million for restricted stock, granted have an exercise price less than the market value of the and $0.4 million for equity grants, and underlying common stock on the date the contingency is
- in 2002, a $6.4 million after-tax, or $10.1 million satisfied. We amortize compensation expense for restricted stock pre-tax comprised of $3.0 million of pre-tax expense for and stock units over the performance/service period, which is certain stock options, $6.6 million for restricted stock, typically a one to five-year period. and S0.5 million for equity grants.
The following table illustrates the effect on net income and In December 2004, the FASB issued SFAS No. 123R.
earnings per share had we applied the fair value recognition *Share-BasredPayment, which changed the accounting for stock-provision of SFAS No. 123 to all outstanding stock options and based compensation to require companies to expense'stock stock awards in each year. options and other equity awards based on their grant-date fair values. We discuss SFAS No. 123R in more detail in the Accounting Standards Issued section later in this Note.
Cash and Cash Equivalents All highly liquid investments with original maturities of three months or less are considered cash equivalents.
Accounts Receivable and Allowance for Uncollectibles Accounts receivable arc stated at the historical carrying amount net of write-offs and allowance for uncollectibles. We establish an allowance for uncollcaibles based on our expected exposure to the credit risk of customers based on a variety of factors.
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Materials, Supplies, and Fuel Stocks Evaluation of Assets for Impairment and Other Than We record our fuel stocks, emissions credits, coal held for resale, Temporary Decline In Value and materials and supplies at the lower of cost or market. We Long-Lived Assets determine cost using the average cost method for all of our We are required to evaluate certain assets that have long lives inventory other than our coal held for resale for which we use (for example, generating property and equipment and real estate) the specific identification method. to determine if they are impaired when certain conditions exist.
SFAS No. 144, Accounting for the Impairment or Disposal of Real Estate Projects Long-Lived Assets, provides the accounting requirements for In Note 4, we summarize the real estate projects that are in our impairments of long-lived assets. We are required to test our Consolidated Balance Sheets. At December 31, 2004, the long-lived assets for recoverability whenever events or changes in projects primarily consist of approximately 190 acres of land circumstances indicate that their carrying amount may not be holdings in various stages of development located at 4 sites in recoverable.
the central Maryland region, including an operating waste water We determine if long-lived assets are impaired by treatment plant located in Anne Arundel County, Maryland. comparing their undiscounted expected future cash flows to their The costs incurred to develop properties are included as part of carrying amount in our accounting records. We would record an the cost of the properties. impairment loss if the undiscounted expected future cash flows from an asset were less than the carrying amount of the asset.
Financial Investments and Trading Securities We are also required to evaluate our equity-method and In Note 4, we summarize the financial investments that are in cost-method investments (for example, in partnerships that own our Consolidated Balance Sheets. power projects) for impairment. APB No. 18, The Equity Method SFAS No. 115, Accountingfor Certain Investments in Debt of Accountingfor Investments in Common Stock, provides the and Equity Securities, applies particular requirements to some of accounting requirements for these investments. The standard for our investments in debt and equity securities. We report those determining whether an impairment must be recorded under investments at fair value, and we use either specific identification APB No. 18 is whether the investment has experienced a loss in or average cost to determine their cost for computing realized value that is considered an Bother than a temporary" decline in gains or losses. We classify these investments as either trading value.
securities or available-for-sale securities, which we describe We use our best estimates in making these evaluations and separately below. We report investments that are not covered by consider various factors, including forward price curves for SFAS No. 115 at their cost. energy, fuel costs, legislative initiatives, and operating costs.
However, actual future market prices and project costs could Trading Securities vary from those used in our impairment evaluations, and the In 2002, our other nonregulared businesses classified some of impact of such variations could be material.
their investments in marketable equity securities and financial limited partnerships as trading securities. We included any Debt and Equity Securities unrealized gains or losses on these securities in "Nonregulated Our investments in debt and equity securities, which primarily revenues" in our Consolidated Statements of Income. We no consist of our nuclear decommissioning trust fund investments, longer hold any investments classified as trading securities for are subject to impairment evaluations under SFAS No. 115, which unrealized gains or losses are recognized in our Accounting for Certain Investments in Debt andEquity Securities.
Consolidated Statements of Income. SFAS No. 115 require us to determine whether a decline in fair value of an investment below the amortized cost basis is other Availabk-for-Sale Securities than temporary. If we determine that the decline in fair value is We classify our investments in the nuclear decommissioning judged to be other than temporary, the cost basis of the trust funds as available-for-sale securities. We describe the investment must be written down to fair value as a new cost nuclear decommissioning trusts and the related asset retirement basis. We discuss EITF 03-1, The Meaning of Other Than obligations in the 'Nuclear Decommissioning" section of this Temporary Impairment and Its Application to CertainInvestments, Note. In addition, we have investments in trust assets securing in the Accounting Standards Issued section later in this note.
certain executive benefits that are classified as available-for-sale securities.
We include any unrealized gains or losses on our available-for-sale securities in "Accumulated other comprehensive income" in our Consolidated Statements of Common Shareholders' Equity and Comprehensive Income and Consolidated Statements of Capitalization.
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Intangible Asets When we retire or dispose of property, plant and Goodwill is the excess of the purchase price of an acquired equipment, we remove the asset's cost from our Consolidated business over the fair value of the net assets acquired. We Balance Sheets. We charge this cost to accumulated depreciation account for goodwill and other intangibles under the provisions for assets that were depreciated under the composite, of SFAS No. 142, Goodwill and Other Intangibk Assets. We do straight-line method. This includes regulated property, plant and not amortize goodwill and certain other intangible assets. SFAS equipment and nonregulated generating assets transferred to our No. 142 requires us to evaluate goodwill and other intangibles merchant energy business. For all other assets, we remove the for impairment at least annually or more frequently if events and accumulated depreciation and amortization amounts from our circumstances indicate the business might be impaired. Goodwill Consolidated Balance Sheets and record any gan or loss in our is impaired if the carrying value of the business exceeds fair Consolidated Statements of Income.
value. Annually, we estimate the fair value of the businesses we The costs of maintenance and certain replacements are have acquired using techniques similar to those used to estimate charged to "Operating expenses" in our Consolidated Statements future cash flows for long-lived assets as previously discussed. If of Income as incurred.
the estimated fair value of the business is less than its carrying value, an impairment loss is required to be recognized to the Deprecation Expense extent that the carrying value of goodwill is greater than its fair We compute depreciation for our generating, electric value. SFAS No. 142 also requires the amortization of intangible transmission and distribution, and gas facilities over the assets with finite lives. We discuss the changes in our intangible estimated useful lives of depreciable property using the following assets in more detail in Note 5. methods:
- the composite, straight-line rates method, approved by Property, Plant and Equipment, Depreciation, the Maryland PSC, applied to the average investment, Amortization, and Accretion of Asset Retirement adjusted for anticipated costs of removal less salvage, in Obligations classes of depreciable property based on an average rate We report our property, plant and equipment at its original cost, of approximately 3.5% per year for our regulated unless impaired under the provisions of SFAS No. 144. business, Our original costs include:
- the composite, straight-line rates applied to the average
- material and labor, investment, in classes of depreciable property based on
- contractor costs, and an average rate of approximately 2.5% per year for the
- construction overhead costs, financing costs, and costs generating assets transferred from BGE to our merchant for asset retirement obligations (where applicable). energy business, or We own an undivided interest in the Keystone and
- the modified units of production method (greater of Conemaugh electric generating plants in Western Pennsylvania, straight-line method or units of production method) for as well as in the transmission line that transports the plants' other generating assets.
output to the joint owners' service territories. Our ownership Other assets are depreciated using the straight-line method interests in these plants are 20.99% in Keystone and 10.56% in and the following estimated useful lives:
Conemaugh. These ownership interests represented a net investment of $191 million at December 31, 2004 and Estimated Useful Lives Asset
$189 million at December 31, 2003. Each owner is responsible for financing its proportionate share of the plants' working Building and improvements 20 - 50 years funds. Working funds arc used for operating expenses and Office equipment and furniture 3 - 20 years capital expenditures. Operating expenses related to these plants Transportation equipment 5 - 15 years are included in 'Operating expenses" in our Consolidated Computer software 3 - 10 years Statements of Income. Capital costs related to these plants are included in "Nonregulated property, plant and equipment" in Amortization Expense our Consolidated Balance Sheets. Amortization is an accounting process of reducing an amount in The 'Nonregulated property, plant and equipment" in our our Consolidated Balance Sheets over a period of time that Consolidated Balance Sheets includes nonregulated generation approximates the useful life of the related item. 'When we reduce construction work in progress of $206.4 million at amounts in our Consolidated Balance Sheets, we increase December 31, 2004 and $184.4 million at December 31, 2003. amortization expense in our Consolidated Statements of Income.
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Accretion Eirpense Nuclear Fuel SFAS No. 143, Accounting for Asset Retirement Obligations We amortize nuclear fuel based on the energy produced over provides the accounting requirements for recognizing an the life of the fuel including the quarterly fees we pay to the estimated liability for legal obligations associated with the Department of Energy for the future disposal of spent nuclear retirement of tangible long-lived asseMs. At December 31, 2004, fuel. These fees are based on the kilowatt-hours of electricity
$821.8 million of our total asset retirement obligation of sold. We report the amortization expense for nuclear fuel in
$825.0 million was associated with our nuclear power plants- "Fuel and purchased energy expenses" in our Consolidated Calvert Cliffs, Nine Mile Point, and Ginna. We have also Statements of Income.
recorded asset retirement obligations associated with our other generating facilities and certain other long-lived assets. We Nuclear Decommissioning record a liability when we are able to reasonably estimate the Effective January 1, 2003, we began to record decommissioning fair value of any future legal obligations associated with expense for Calvert Cliffs Nuclear Power Plant (Calvert Cliffs) retirement that have been incurred and capitalize a in accordance with SFAS No. 143 Accountingfor Asset corresponding amount as part of the book value of the related Retirement Obligations (SFAS 143). The "Asset retirement long-lived assets. The increase in the capitalized cost is included obligations" liability associated with the decommissioning of in determining depreciation expense over the estimated useful Calvert Cliffs was $286.1 million at December 31. 2004 and life of these assets. Since the fair value of the asset retirement $265.5 million at December 31, 2003. Our contributions to obligations is determined using a present value approach, the nuclear decommissioning trust funds for Calvert Cliffs were accretion of the liability due to the passage of time is $22.0 million for 2004, $13.2 million for 2003 and recognized each period to "Accretion of asset retirement $17.6 million for 2002. Under the Maryland PSC's order obligations" in our Consolidated Statements of Income until deregulating electric generation, BGE's customers must pay a the settlement of the liability. We record a gain or loss when total of $520 million in 1993 dollars, adjusted for inflation, to the liability is settled after retirement. decommission Calvert Cliffs. BGE is collecting this amount on The change in our 'Asset retirement obligations" liability behalf of and passing it to Calvert Cliffs Nuclear Power during 2004 was as follows: Plant, Inc. Calvert Cliffs Nuclear Power Plant, Inc. is responsible for any difference between this amount and the actual costs to decommission the plant.
(In millions)
We began to record decommissioning expense for Nine Liability at January 1, 2004 $595.9 Mile Point Nuclear Station (Nine Mile Point) in accordance liabilities incurred 177.9 Liabilities settled with SFAS No. 143 on January 1, 2003. The 'Asset retirement Accretion expense 53.2 obligations" liability associated with the decommissioning was Other (2.0) $351.5 million at December 31, 2004 and $326.2 million at Revisions to cash flows December 31, 2003. We determined that the decommissioning Liability at December 31, 2004 $825.0 trust funds established for Nine Mile Point are adequately funded to cover the future costs to decommission the plant and
'Liabilities incurred" in the table above primarily reflect as such, no contributions were made to the trust funds during the asset retirement obligation recorded in connection with our the years ended December 31, 2004, 2003, and 2002.
acquisition of the RE. Ginna Nuclear Power Plant (Ginna). Upon the dosing of the Ginna acquisition in 2004, the We discuss the acquisition of Ginna in more detail in Note 15. seller transferred $200.8 million in decommissioning funds. In "Other" in the table above represents the asset retirement return, we assumed all liability for the costs to decommission obligation associated with our geothermal facility in Hawaii the unit. We believe that this transfer will be sufficient to cover that was sold in the quarter ended June 2004. At the time of the future costs to decommission the plant and as such, no the sale, the asset retirement obligation was transferred to the contributions were made to the trust funds during the year buyer of the geothermal facility. We discuss the sale of the ended December 31, 2004. Effective June 2004, we began to geothermal facility in more detail in Note 2. record decommissioning expense for Ginna in accordance with SFAS No. 143. The 'Asset retirement obligations" liability associated with the decommissioning was $184.2 million at December 31, 2004. WeVdiscuss the acquisition of Ginna in more detail in Note 15.
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In accordance with Nuclear Regulatory Commission Long-Term Debt (NRC) regulations, we maintain external decommissioning We defer all costs related to the issuance of long-term debt.
trusts to fund the costs expected to be incurred to These costs include underwriters' commissions, discounts or decommission Calvert Cliffs, Nine Mile Point and Ginna. The premiums, other costs such as legal, accounting, and regulatory NRC requires utilities to provide financial assurance that they fees, and printing costs. We amortize these costs into interest will accumulate sufficient funds to pay for the cost of nuclear expense over the life of the debt.
decommissioning. The assets in the trusts are reported in WVhen BGE incurs gains or losses on debt that it retires "Nuclear decommissioning trust funds" in our Consolidated prior to maturity, it amortizes those gains or losses over the Balance Sheets. These amounts are legally restricted for funding remaining original life of the debt.
the costs of decommissioning. We dassify the investments in the nuclear decommissioning trust funds as available-for-sale Accounting Standards Issued securities, and we report these investments at fair value in our SFAS 123 Revised Consolidated Balance Sheets as previously discussed in this In December 2004, the FASB issued SPAS No. 123 Revised Note. Investments by nuclear decommissioning trust funds are (SFAS No. 123R), Share-BasedPayment. SPAS No. 123R guided by the 'prudent man" investment principle. The funds revises SFAS No. 123, Accountingfor Stock-Based Compensation, are prohibited from investing directly in Constellation Energy and supersedes APB No. 25, Accountingfor Stock Issued to or its affiliates and any other entity owning a nuclear power Employees. SFAS No. 123R requires companies to recognize plant. compensation expense for all equity-based compensation awards As the owner of Calvert Cliffs, we are required, along issued to employees. Equity-based compensation awards include with other domestic utilities, by the Energy Policy Act of 1992 stock options, restricted stock, and any other share-based to make contributions to a fund for decommissioning and payments. Under SPAS 123R, we must recognize compensation decontaminating the Department of Energy's uranium cost over the period during which an employee is required to enrichment facilities. The contributions are paid by BGE and provide service in exchange for the award. We estimate the fair generally payable over 15 years with escalation for inflation and value of employee stock options using option-pricing models are based upon the proportionate amount of uranium enriched adjusted for the unique characteristics of those instruments.
by the Department of Energy for each utility. BGE amortizes We plan to adopt SFAS No. 123R effective July 1, 2005 the deferred costs of decommissioning and decontaminating the using the Modified Prospective Application method without Department of Energy's uranium enrichment facilities. The restatement of prior interim periods. Under this method, we previous owners retained the obligation for Nine Mile Point will begin to amortize compensation cost for the remaining and Ginna. portion of our outstanding awards on the adoption date for which the requisite service has not yet been rendered.
Capitalized Interest and Allowance for Funds Used Compensation cost for these awards will be based on the fair During Construction value of those awards as disclosed on a pro-forma basis under CapitalizedInterest SFAS 123 in the Stock-Based Compensation section of this note.
Our nonregulated businesses capitalize interest costs under We will account for awards that are granted, modified, or SPAS No. 34, Capitalzing Interest Costs, for costs incurred to settled after the adoption date in accordance with SFAS finance our power plant construction projects, real estate No. 123R.
developed for internal use, and other capital projects. Currently, we are evaluating the impact of adopting this standard on our financial results. However, we do not believe Allowance for Funds Used During Construction (AFC) the impact of this standard on our ongoing operating results BGE finances its construction projects with borrowed funds will be materially different than the results as disclosed on a and equity funds. BGE is allowed by the Maryland PSC to pro-forma basis in the Stock-Based Compensation section of this record the costs of these funds as part of the cost of note.
construction projects in its Consolidated Balance Sheets. BGE does this through the AFC, which it calculates using rates EITF 03-1 authorized by the Maryland PSC. BGE bills its customers for In March 2004, the EITF reached a consensus on Issue 03-1, the AFC plus a return after the utility property is placed in The Meaning of Other Than Temporary Impairment and Its service. Application to Certain Investments, related to measurement and The AFC rates are 9.4% for electric plant, 8.6% for gas recognition criteria that would have become effective July 1, plant, and 9.2% for common plant. BGE compounds AFC 2004. In accordance with Nuclear Regulatory Commission annually. regulations, we do not manage the day-to-day activities of our nudear decommissioning trust funds. As a result, a strict interpretation of EITF 03-1 would indicate that we do not have the ability and intent to hold investments whose market value is less than our cost until recovery.
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In September 2004, the FASB issued FSP EITF 03-1-1 FIN 46/FIN 46R which delayed the implementation of the measurement and In January 2003, the FASB issued FIN 46, Consolidation of recognition criteria until additional implementation guidance Variable Interest Entities, which was subsequently revised in its could be developed. If relief from the strict interpretation entirety with the issuance of FIN 46R in December 2003.
previously discussed is not induded in the pending FASB FIN 46R establishes conditions under which an entity implementation guidance, we would be required to record into must be consolidated based upon variable interests rather than earnings any dedine in market value below the cost of our voting interests. Variable interests are ownership interests or nuclear decommissioning investments. If this interpretation of contractual relationships that enable the holder to share in the EITF 03-1 had become effective at December 31, 2004, we financial risks and rewards resulting from the activities of a would have been required to record a pre-tax charge of Variable Interest Entity (VIE). A VIE can be a corporation, approximately $2.8 million. We have approximately $1 billion partnership, trust, or any other legal structure used for business invested in nuclear decommissioning trust assets. Therefore, a purposes. An entity is considered a VIE under FIN 46R if it one percent dedine in all of our investments below book value does not have an equity investment sufficient for it to finance would result in approximately a $10 million pre-tax charge. We its activities without assistance from variable interest holders or cannot predict the outcome of the implementation guidance. if its equity investors lack any of the following characteristics of However, the impact could be material to our financial results. a controlling financial interest:
- control through voting rights, Accounting Standards Adopted
- obligation to absorb expected losses, or FSP 106-2
- right to receive expected residual returns.
In May 2004, FASB Staff Position (FSP) 106-2 was issued, FIN 46R requires us to consolidate VIEs for which we are which addresses accounting and disclosure requirements the primary beneficiary and to disclose certain information pertaining to the Medicare Prescription Drug Improvement and about significant variable interests we hold. The primary Modernization Act of 2003. FSP 106-2 is effective July 1, beneficiary of a VIE is the entity that receives the majority of a 2004. We discuss the impacts of the Medicare Prescription VIE's expected losses, expected residual returns, or both.
Drug Improvement and Modernization Act of 2003 recorded FIN 46R was effective March 31, 2004, for all VIEs in accordance with FSP 106-2 in Note 7. except special purpose entities (SPEs), for which the effective date was December 31, 2003. Therefore, at December 31, FSP 109-2 2003, we and BGE deconsolidated BGE Capital Trust II, an In the fourth quarter of 2004, the President signed into law SPE established to issue trust preferred securities as described the American Jobs Creation Act of 2004 (the Act) that in Note 9, because BGE is not its primary beneficiary. As a provides a temporary incentive for U. S. multinational result, we currently record $257.7 million of deferrable interest companies to repatriate foreign earnings. The temporary subordinated debentures due to BGE Capital Trust 11, and incentive for U. S. companies to repatriate accumulated foreign $7.7 million equity investment in BGE Capital Trust 11 in earnings provides an elective, 85 percent dividends received "Other assets" in our and BGE's Consolidated Balance Sheets.
deduction for certain dividends from controlled foreign As a result of adopting the remainder of the provisions of corporations that will be reinvested in the United States. FIN 46R as of March 31, 2004, we were not required to In response to the issuance of the Act, in December 2004, consolidate or deconsolidate any non-SPE entities with which the FASB issued FSP No. 109-2, Accounting andDisclosure we are involved through variable interests. We had preliminarily Guidancefrr the Foreign Earnings Repatriation Provision within determined that we were the primary beneficiary for an the American Jobs CreationAct of 2004. FSP No. 109-2 unconsolidated investment in a hydroelectric generating plant provides companies with additional time to evaluate the impact located in Pennsylvania because our two-thirds interest in the of the Act and provides accounting and disclosure guidance for plant's earnings are disproportionate to our 50% voting applying the foreign earnings repatriation provisions of the Act. interest. However, we subsequently determined that the entity In December 2004, we repatriated $15 million in the form of is not a VIE because less than substantially all of the plant's a dividend from our Panamanian distribution facility, which we activities are conducted on our behalf, and therefore we do nor plan to reinvest in the United States to take advantage of the have to consolidate the entity.
dividends received deduction. Since we previously provided We have a significant interest in the following VIEs for federal deferred income taxes on the earnings of our foreign which we are not the primary beneficiary.
subsidiary that issued the dividend, in 2004 we recorded a net reduction of $4.4 million in federal tax expense in connection Nature of Date of with the earnings repatriation. VIE Involvement Involvement Power projects and Equity investment Prior to 2003 fuel supply entities and guarantees Natural gas Volumetric and price July 2003 producing facility swap 83
The following is summary information about these entities The maximum exposure to loss represents the loss that we as of December 31, 2004: would incur in the unlikely event that our interests in all of these entities were to become worthless and we were required to fund the full amount of all guarantees associated with these (In millions) entities. Our maximum exposure to loss as of December 31, Total assets $291.1 2004 consists of the following:
Total liabilities 147.0
- the carrying amount of our investment totaling Our ownership interest 41.1
$41.1 million, Other ownership interests 103.0
- debt and performance guarantees totaling Our maximum exposure to loss 75.3 S 13.4 million, and
- volumetric and price variability of up to $20.8 million associated with a natural gas producer swap, based on contract volumes and gas prices as of December 31, 2004.
We assess the risk of a loss equal to our maximum exposure to be remote.
2 Workforce Reduction, Impairment Losses, and Other Events 2004 Events The fair value of the facility as of March 31, 2004, based on the bids under consideration, was below carrying value.
Pre-Tax After-Tax Therefore, we recorded a $71.6 million pre-tax, or $47.3 million (In millions) after-tax, impairment charge during the first quarter of 2004.
Loss from discontinued operations $(75.6) $(49.1) We reported the after-tax impairment charge as a component of Recognition of 2003 synthetic fuel tax "Loss from discontinued operations" in our Consolidated credits - 35.9 Statements of Income. Additionally, we recognized $1.5 million Workforce reduction costs (9.7) (5.9) pre-tax, or $1.0 million after-tax, of earnings from the facility Impairment losses and other costs (3.7) (2.2) for the quarter ended March 31, 2004 as a component of "Loss Net loss on sales of investments and from discontinued operations."
other assets (1,2) (0.6) In June 2004, we completed the sale of the facility. Based on the final sales price and other costs incurred over the Total special items $(90.2) $(21.9) remainder of the year, we recognized an additional loss of
$5.5 million pre-tax, or $2.8 million after-tax. The sale of this Loss from Discontinued Operations facility was reflected in our merchant energy business reportable In the fourth quarter of 2003, we began to re-evaluate our segment. In addition, as a result of a current audit relating to strategy regarding our geothermal generating facility in Hawaii. prior tax years for this facility, we could record additional gain The reevaluation of our strategy included soliciting bids to or loss from discontinued operations in future periods.
determine the level of interest in the facility. As of We have not reclassified the prior year results of operations, December 31, 2003, management determined that disposal of which were reported under the equity method as "Nonregulated the facility was more likely than not to occur. As a result, we revenues," based on the immateriality of the amounts involved.
evaluated the facility for impairment as of December 31, 2003, The facility had a $4.0 million net loss, including a $1.1 million in accordance with SPAS No. 144, Accountingfor the Impairment cumulative effect of change in accounting principle for the or Disposal ofLong-Lived Assets, and determined that the facility adoption of SFAS No. 143, during 2003.
was not impaired primarily due to indicative bids from third parties above the carrying value of the assets.
In March 2004, after reviewing final binding offers, management committed to a plan to sell the facility that met the 'held for sale" criteria under SPAS No. 144. Under SPAS No. 144, we record assets and liabilities held for sale at the lesser of the carrying amount or fair value less cost to sell.
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Synthetic Fuel Tax Credits 2003 Events In 2003, we purchased 99% ownership in a South Carolina facility that produces synthetic fuel. We did not recognize in our Pre-Tax After-Tax Consolidated Statements of Income the tax benefit of (In millions)
$35.9 million for credits claimed on our South Carolina facility Workforce reduction costs $ (2.1) S (1.3) in 2003 pending receipt of a favorable private letter ruling. In Reduction of financial investment (0.6) (0.4)
April 2004, we received a favorable private letter ruling. We Net gain on sales of investments and believe receipt of the private letter ruling provides assurance that other assets 26.2 16.4 it is highly probable that the credits will be sustained. Therefore, Total special items $23.5 $14.7 we recognized the tax benefit of $35.9 million in our Consolidated Statements of Income in 2004. We discuss the synthetic fuel tax credits in more detail in NMore 0. Workforre Reduction Costs During 2003, we recorded $2.1 million in pre-tax expense, or Workforce Reduction Costs $1.3 million after-tax, of which BGE recorded $0.7 million In the fourth quarter of 2004, we approved a restructuring of pre-tax, associated with deferred payments to employees eligible the work forces of the Nine Mile Point and Calvert Cliffs for the 2001 Voluntary Special Early Retirement Program.
nuclear generating stations that was effective in January 2005. In In 2004, we completed the 2002 workforce reduction connection with this restructuring, approximately 108 employees programs. As a result, no involuntary severance liability was will receive severance and other benefits under our existing recorded under EITF 94-3, Liability Recognition for Certain benefit programs. At December 31, 2004, we accrued the Employee Termination Benefits and Other Costs to Eit an Activity estimated total cost of this reduction in workforce of (including Certain Costs Incurredin a Restructuring), at
$9.7 million pre-tax, or $5.9 million after-tax, in accordance December 31, 2004.
with applicable accounting requirements.
Impairment Losses and Other Costs Impairment of FinancialInvestment In 2003, our other nonregulated businesses recognized an Our other nonregulated businesses recognized a pre-tax impairment loss of $0.6 million pre-tax, or $0.4 million impairment loss of $3.7 million, or $2.2 million after-tax, after-tax, related to the decline in value of our investment in an during the year ended December 31, 2004 related to an other airplane.
than temporary decline in fair value of certain financial investments. Net Gain on Sales of Investments and Other Assets During 2003, our other nonregulated businesses recognized Net Loss on Saks of Investments and Other Assets $26.2 million of pre-tax, or $16.4 million after-tax, gains on the Our other nonregulated businesses recognized a pre-tax loss of sales of non-core assets as follows:
$1.2 million, or $0.6 million after-tax, during the year ended
- a $13.1 million pre-tax gain on the sale of certain real December 31, 2004 on the sale of non-core assets as follows: estate,
- a $1.1 million pre-tax gain in the first quarter on an
- a $7.2 million pre-tax gain on the sale of an oil tanker installment sale of real estate, to the U.S. Navy,
- a $0.4 million pre-tax gain in the first quarter on the
- a $5.3 million pre-tax gain on the favorable settlement sale of a financial investment, of a contingent obligation we had previously reserved
- a $3.3 million pre-tax gain in the second quarter on the relating to the sale of our Guatemalan power plant sale of a financial investment, operation in the fourth quarter of 2001, and
- a $1.1 million pre-tax gain in the second quarter on the
- a $0.6 million pre-tax gain on the sale of financial sale of real estate, investments.
- a $7.5 million pre-tax loss in the third quarter on the sale of a financial investment, and HurricaneIsabel
- a $0.4 million pre-tax gain in the fourth quarter on the In September 2003, Hurricane Isabel caused damage to the sale of a financial investment. electric and gas distribution system of BGE. As a result, BGE incurred capitalized costs of $32.0 million and maintenance expenses of $36.8 million, or $22.2 million after-tax to restore its distribution system. The maintenance expenses included
$32.1 million pre-tax, or $19.4 million after-tax, of incremental expenses.
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2002 Events
- We recorded $29.6 million of settlement charges related to our pension plans under SFAS No. 88, Employers' Pre-Tax After-Tax Accobantingfor Settlements and Curtailments of Defined (In millions) Benefit Pension Plans andfor Termination Benefits. These Workforce reduction costs: charges reflect the recognition of actuarial gains and Costs associated with 2001 programs $ (50.8) $ (30.8) losses associated with employees who have retired and Costs associated with programs taken their pension in the form of a lump-sum initiated in 2002 (12.0) (7.2) payment. Under SFAS No. 88, the settlement charge Total workforce reduction costs (62.8) (38.0) could not be recognized until lump-sum pension payments exceeded annual pension plan service and Impairment losses and other costs: interest cost, which occurred in 2002.
Impairments of investments in
- We recorded a $1.6 million expense associated with qualifying facilities and power deferred payments to employees eligible for the VSERP.
projects (14.4) (9.9)
- Partially offsetting these costs, we reversed approximately Costs associated with exit of BGE S2.6 million of previously accrued workforce reduction Home merchandise stores (9.0) (6.1) costs primarily as a result of the reversal of education Impairments of real estate and and outplacement assistance benefits we accrued that international investments (1.8) (1.2) employees did not utilize to the extent expected.
Total impairment losses and other In 2002, we completed the 2001 workforce reduction costs (25.2) (17.2) programs. Accordingly, no involuntary severance liability Net gain on sales of investments and recorded under EITF 94-3 remained at December 31, 2002.
other assets 261.3 166.7 Costs associatedwith 2002 Programs Total special items $173.3 $111.5 In 2002, we recorded $12.0 million of expenses for anticipated involuntary severance costs in accordance with EITF 94-3 Workforce Reduction Costs associated with new workforce reduction initiatives as follows:
During 2002, we incurred costs related to workforce reduction
- We recorded $8.5 million for workforce reduction costs efforts initiated in the fourth quarter of 2001 as discussed in for the severance of 120 employees at Calvert Cliffs this note and additional initiatives undertaken in the third Nuclear Power Plant (Calvert Cliffs).
quarter of 2002. We discuss these costs in more detail below.
- We recorded $1.6 million of workforce reduction costs for the severance of 27 employees in our information Costs associated with 2001 Programs technology organization. BGE recorded $0.6 million of In 2002, we recorded $63.7 million of net workforce reduction this amount.
costs associated with our 2001 workforce reduction initiatives as
- We recorded $1.9 million of workforce reduction costs discussed below. The $63.7 million included $50.8 million for the severance of 20 employees in our legal recognized as expense, of which BGE recognized $33.8 million. organization. BGE recorded $0.9 million of this The remaining $12.9 million was recognized by BGE as a amount.
regulatory asset related to its gas business as discussed in Note 6. At December 31, 2002, the involuntary severance liability
- We recorded $52.9 million when 308 employees elected recorded under EITF 94-3 for our 2002 workforce reduction the age 50 to 54 Voluntary Special Early Retirement programs was $12.0 million.
Program (VSERP).
- We reversed $17.8 million of the $25.1 million Impairment Losses and Other Costs involuntary severance accrual that was recorded in 2001 Investments in QualifiingFacilities and Power Projects to reflect the employees that elected the age 50 to 54 In the third quarter of 2002, our merchant energy business VSERP. Ultimately, we involuntarily severed 129 recorded impairment losses on certain of the investments in employees that resulted in a total cost for the qualifying facilities and power projects totaling $14.4 million involuntary severance program of $7.3 million. under the provisions of APB No. 18. We describe these investments in Note 4. The provisions of APB No. 18 require that an impairment loss be recognized when an investment experiences a loss in value that is other than temporary as discussed in Note 1.
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During the third quarter of 2002, we performed an analysis Real Estate andInternationalInvestments of whether any of the investments were impaired. As a result of We changed our strategy from an intent to hold to an intent to our analysis, we concluded that the declines in value of sell for certain of our non-core assets in 2001. During 2002, we particular investments in certain qualifying facilities and power determined that the fair value of several real estate projects and projects were other than temporary in nature under the our investment in a South American generation project declined provisions of APB No. 18 and we recognized the following losses below their respective book values due to deteriorating market in 2002: conditions for these projects. Accordingly, we recorded losses
- We recognized a $5.2 million other than temporary that totaled $1.8 million for these projects in accordance with decline in value of our investment in a partnership that SFAS No. 144 and APB No. 18.
owns a geothermal project in Nevada. This project experienced a well implosion and we believe that the Net Gain on Sales of Investments and OtherAssets expected cash flows from the project will not be In February 2002, Reliant Resources, Inc. acquired all of the sufficient to recover our equity interest in that outstanding shares of Orion Power Holdings, Inc. (Orion) for partnership. $26.80 per share, including the shares we owned of Orion. We
- We recognized a $2.6 million other than temporary received cash proceeds of $454.1 million and recognized a gain decline in value of our investment in a fuel processing of $255.5 million on the sale of our investment.
site in Pennsylvania where the expected cash flows from In the fourth quarter of 2001, we announced our decision a sublease are no longer expected to be sufficient to to focus efforts and capital on core domestic energy businesses recover our lease costs associated with this site. and undertook a plan to sell a number of non-core businesses
- We recognized a $6.6 million other than temporary and investments. In 2002, we made further progress on this decline in value of our investment in a partnership that initiative, and recognized approximately $5.8 million in net owns a waste burning power project in Michigan. In gains from the sale of several non-core assets including:
2001, we recognized a $6.1 million pre-tax impairment
- Our other nonregulated businesses recognized gains loss on this investment because we expected operating totaling $6.7 million on the sale of several parcels of cash flows would not be sufficient to pay existing debt real estate and financial investments.
service and that we would not be able to recover our
- In October 2002, we sold all of our 18 senior-living equity investment. However, at that time, we believed facilities for $77.2 million that represents a combination that we would recover our senior working capital loans of cash and the assumption by the buyer of existing receivable and accounts receivable for operating the mortgages. Our other nonregulated businesses recognized project. As of the third quarter of 2002, the operating a $2.8 million gain on the sale of our entire ownership performance of the project did not improve as expected, interest in these facilities.
and we believed the expected future cash flows were no
- Our merchant energy business recognized a $2.3 million longer sufficient to recover these receivables. Therefore, gain on the sale of a discontinued wind-powered we recognized an additional impairment loss on this development project.
investment.
- In 2001, our merchant energy business recognized an impairment loss on four turbines, associated with a Closing of BGE Home Retail Merchandise Stores discontinued development program. Since that time, In September 2002, we announced our decision to dose our many other companies canceled development projects BGE Home retail merchandise stores. In connection with that and the market values for turbines have declined decision, we recognized $9.5 million in exit costs. We recognized significantly. Orders for three of the four turbines were
$2.9 million related to expected severance costs for 93 employees canceled with termination fees paid to the manufacturer and $2.9 million of costs in connection with the termination of consistent with the amount recognized in leases for the eight stores and other exit costs in accordance with December 2001. The fourth turbine-generator set was EITF 94-3. sold during 2002 for $6.0 million below its book value.
We also recognized $3.2 million for the write-off of unamortized leasehold improvements in accordance with SFAS No. 144, and $0.5 million for the write-down of inventory to a lower-of-cost-or-market valuation in accordance with Accounting Research Bulletin No. 43, Restatement and Revision ofAccounting Research Bulletins. The $0.5 million is included in "Operating expenses" in our Consolidated Statements of Income.
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3 Information by Operating Segment Our reportable operating segments are-Merchant Energy, Our remaining nonregulated businesses:
Regulated Electric, and Regulated Gas:
- design, construct, and operate heating, cooling, and
- Our nonregulated merchant energy business includes: cogeneration facilities for commercial, industrial, and
- full requirements load-serving sales of energy and municipal customers throughout North America, and capacity to utilities and commercial and industrial
- provide home improvements, service electric and gas customers, appliances, service heating, air conditioning, plumbing,
- structured transactions and risk management electrical, and indoor air quality systems, and provide services for various customers (including hedging natural gas marketing to residential customers in central of output from generating facilities and fuel Maryland.
costs), In addition, we own several investments that we do not
- gas retail energy products and services to consider to be core operations. These include financial commercial and industrial customers, investments, real estate projects, and interests in Panamanian
- fossil, nuclear, and hydroelectric generating distribution facility and in a fund that holds interests in two facilities and interests in qualifying facilities, fuel South American energy projects.
processing facilities, and power projects in the Our Merchant Energy, Regulated Electric, and Regulated United States, Gas reportable segments are strategic businesses based principally
- coal sourcing services for the variable or fixed upon regulations, products, and services that require different supply needs of North American and technology and marketing strategies. We evaluate the international power generators, and performance of these segments based on net income. We
- operations and maintenance consulting services. account for intersegment revenues using market prices. We
- Our regulated electric business purchases, transmits, present a summary of information by operating segment on the distributes, and sells electricity in Maryland. next page.
- Our regulated gas business purchases, transports, and sells natural gas in Maryland.
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Reportable Segments Merchant Regulated Regulated Other Energy Electric Gas Nonregulated Business Business Business Businesses Eliminations Consolidated (In millions) 2004 Unaffiliated revenues $ 9,405.3 $1,967.6 $ 755.0 $421.8 $ - $12,549.7 Intersegment revenues 984.6 0.1 2.0 0.2 (986.9)
Total revenues 10,389.9 1,967.7 757.0 422.0 (986.9) 12,549.7 Depreciation and amortization 248.0 194.2 48.1 35.2 - 525.5 Fixed charges 196.2 803 29.1 24.7 330.3 Income tax expense 69.2 86.8 15.9 0.3 - 172.2 Loss on discontinued operations (49.1) - - - - (49.1)
Net income (loss) (a) 389.9 131.1 22.2 (3.5) - 539.7 Segment assets 12,395.6 3,402.2 1,163.4 675.7 (289.8) 17,347.1 Capital expenditures 455.0 209.0 56.0 42.0 - 762.0 2003 Unaffiliated revenues $ 6,465.9 $1,921.5 $ 712.7 $587.7 $ - $ 9,687.8 Intersegment revenues 1,167.0 0.1 13.3 0.2 (1,180.6)
Total revenues 7,632.9 1,921.6 726.0 587.9 (1,180.6) 9,687.8 Depreciation and amortization 229.5 181.7 46.6 21.2 - 479.0 Fixed charges 191.9 96.8 28.2 21.0 2.3 340.2 Income tax expense 146.9 73.5 32.0 17.1 - 269.5 Cumulative effects of changes in accounting principles (198.4) - - - _ (198.4)
Net income (b) 114.6 107.5 43.0 12.2 - 277.3 Segment assets 10,503.7 3,512.0 1,069.1 778.7 (270.5) 15.593.0 Capital expenditures 419.0 236.0 53.0 53.0 - 761.0 2002 Unaffiliated revenues $ 1,645.1 $1.965.6 $ 570.5 $537.4 $ - $ 4,718.6 Intersegment revenues 1,136.2 0.4 10.8 - (1,147.4)
Total revenues 2,781.3 1,966.0 581.3 537.4 (1.147.4) 4,718.6 Depreciation and amortization 242.8 174.2 47.4 16.6 481.0 Fixed charges 102.0 128.4 25.9 25.2 281.5 Income tax expense 127.2 70.6 23.0 88.8 309.6 Net income (c) 247.2 99.3 31.1 148.0 525.6 Segment assets 9,680.4 3,565.1 1,140.4 913.0 (355.6) 14,943.3 Capital expenditures 641.0 167.0 50.0 65.0 923.0 Certainprior-year amounts have been reclassified to conform with the current years presentation.
(a) Our merchant energy business and our other nonregulatedbusinesses recognized after-tax charges (income) of ($30.0 milion) and
$2.8 million, respectively,for recognition of 2003 syntheticfuel tax credits, workforce reduction costs, impairment losses and other costs, and net losses on sales of investments and other assets as described in more detail in Note 2.
(b) Our merchant energy business, our regulatedelectric business, our regulatedgas business, and our other nonregulated businesses recognized after-tax charges (income) of $0.7 million, $0.4 million, $0.1 million, and ($15.9 million), respectively, for workforce reduction costs, impairment losses and other costs, and net gains on sales of investments and other assets as described in more detail in Note 2 (c) Our merchant energy business, our regulated electric business, our regulatedgas business, and our other nonregulated businesses recognizedafter-tax charges (income) of $28.3 milion, $20.5 million, $0.8 million, and ($161.1 million), respectively, for workforce reduction costs, business exit costs, impairment losses and other costs, and net gains on sales of investments and other assets as described in more detail in Note 2.
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4Investments Real Estate Projects Financial Investments Real estate projects recorded in 'Other assets" were Financial investments recorded in "Other assets' consist of the
$28.8 million at December 31, 2004 and $44.3 million at following:
December 31, 2003.
At December 31, 2004 2003 Investments in Qualifying Facilities and Power Projects (In millions)
Our merchant energy business holds up to a 50% voting interest Financial limited partnerships $5.7 $22.5 in 24 operating domestic energy projects that consist of electric Leveraged leases - 2.8 generation, fuel processing, or fuel handling facilities. Of these 24 projects, 17 are "qualifying facilities" that receive certain Total financial investments $5.7 $25.3 exemptions and pricing under the Public Utility Regulatory Policy Act of 1978 based on the facilitiesenergy source or the Investments Classified as Available-for-Sale use of a cogeneration process. We classify the following investments as available-for-sale:
Investments in qualifying facilities and domestic power
- nudear decommissioning trust funds, and projects held by our merchant energy business consist of the
- trust assets securing certain executive benefits.
following: This means we do not expect to hold them to maturity, and we do not consider them trading securities.
At December 31, 2004 2003 We show the fair values, gross unrealized gains and losses, (In millions) and amortized cost basis for all of our available-for-sale securities, in the following tables. We use specific identification Coal $128.7 $130.5 to determine cost in computing realized gains and losses.
Hydroelectric 55.8 57.3 Geothermal 46.3 56.0 hir Amortized Unrealized Unrealized Biomass 50.2 51.4 At December 31, 2004 Cost Basis Gains Losses Value Fuel Processing 22.5 22.5 Solar 10.4 10.5 (In millions)
Marketable equity Total $313.9 $328.2 securities $786.1 $72.5 $(2.5) $ 856.1 Corporate debt and U.S.
The investment in qualifying facilities and domestic power treasuries 73.7 0.7 (0.2) 74.2 projects were accounted for under the following methods:
State municipal bonds 94.3 2.9 (0.2) 97.0 At December 31, 2004 2003 Totals $954.1 $76.1 S(2.9) $1,027.3 (In millions) Amortized Unrealized Unrealized hir Equity method $303.5 $317.6 At December 31) 2003 Cost Basis Gains Losses Value Cost method 10.4 10.6 (In millions)
Total power projects $313.9 $328.2 Marketable equity securities $644.8 $30.7 $(22.2) $653.3 Corporate debt and U.S.
Our percentage voting interest in qualifying facilities and treasuries 37.2 0.9 - 38.1 domestic power projects accounted for under the equity method State municipal bonds 48.4 4.3 - 52.7 ranges from 16% to 50%. Equity in earnings of these power projects were $18.0 million in 2004, $2.1 million in 2003, and Totals $730.4 $35.9 $(22.2) $744.1
$9.1 million in 2002. Certain prior-year amounts hae been reclassified to conform with Our power projects include investments of $240.2 million the current year! presentation.
in 2004 and $251.8 million in 2003 that sell electricity in California under power purchase agreements called 'Interim In addition to the above securities, the nuclear Standard Offer No. 4" agreements. decommissioning trust funds induded $30.6 million at Our other nonregulated businesses also held international December 31, 2004 and S17.2 million at December 31, 2003 of energy projects accounted for under the equity method of cash and cash equivalents.
$4.5 million at December 31, 2004 and $4.4 million at December 31, 2003.
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The preceding tables include $73.3 million in 2004 of net Gross and net realized gains and losses on available-for-sale unrealized gains and $13.7 million in 2003 of net unrealized securities, excluding the gains on our sales of the Orion gains associated with the nuclear decommissioning trust funds investment, were as follows:
that are rceflected as a change in the nuclear decommissioning trust funds in our Consolidated Balance Sheets. 2004 2003 2002 We have unrealized losses relating to certain (In millions) available-for-sale investments included in our decommissioning trust funds. We believe these losses are temporary in nature and Gross realized gains $ 4.1 $ 6.7 S 6.0 expect the investments to recover their value in the future given Gross realized losses (7.7) (6.1) (9.5) the long-term nature of these investments. Decommissioning will Net realized (losses) gains $(3.6) $0.6 5(3.5) not occur until the operating licenses for our nudear facilities expire. We show the fair values and unrealized losses of our Gross realized losses for 2004 indude $4.5 million pre-tax investments that were in a loss position at December 31, 2004 impairment charge we recognized on a nudear decommissioning and 2003. trust fund investment that we believed represented an other than temporary decline in value.
At December 31, 2004 The corporate debt securities, U.S. Government agency Less than 12 obligations, and state municipal bonds mature on the following months 12 months or more Total schedule:
Description of Fair Unrealized Fsir Unrealized Fair Unrealized Securities Value Losses Value Losses Value Losses At December 31, 2004 (In millions) (In millions)
Marketable Less than 1 year S 15.6 equity 1-5 years 42.2 securities $ 23.6 S(2.4) S - $ - $ 23.6 $ (2.4) 5-10 years 69.3 Corporate debt More than 10 years 44.1 and U.S. Total maturities of debt securities S 171.2 treasuries 15.3 (0.1) 10.1 (0.1) 25.4 (0.2)
State municipal bonds 18.7 (0.2) 3.3 - 22.0 (0.2)
Total temporarily impaired securities $ 57.6 5(2.7) $ 13.4 $ (0.1) $ 71.0 S (2.8)
At December 31, 2003 Less than 12 months 12 months or more Total Description of Fair Unrealized Fair Unrealized Fair Unrealized Securities Value Losses Value Losses Value Losses (In millions)
Marketable equity securities $210.7 5(2.7) $308.2 $(19.2) $518.9 5(21.9)
Corporate debt and U.S.
treasuries 16.9 - - - 16.9 -
State municipal bonds - - 0.7 - 0.7 -
Total temporarily impaired securities $227.6 $(2.7) $308.9 S(19.2) $536.5 S(21.9) 91
5 Intangible Assets Goodwill Acquired energy contracts (net) represent the fair value of a Goodwill is the cost of an acquisition less the fair value of the contract at the time of contract acquisition, which includes net assets acquired. Our goodwill balance is primarily related to contracts acquired as part of a business, asset, or portfolio our merchant energy business acquisitions that occurred in 2002 acquisition. Energy contracts acquired in connection with a and 2003. We discuss our acquisitions in more detail in business combination can either be an asset or a liability and are Note 15. The changes in the carrying amount of goodwill for reflected on a net basis in the table above.
the years ended December 31, 2004 and 2003 are as follows: We recognized amortization expense related to our intangible assets as follows:
Balance ax Goodwill Balance at 2004 January 1. Acquired Other(z) December 31. * $114.2 million, of which BGE recognized
$41.4 million, during 2004 (In millions)
Goodwill $ 146.3 $ - $(l.5) $ 144.8
- $84.6 million, of which BGE recognized $33.0 million, during 2003, and Balance at Goodwill Balance at * $46.4 million, of which BGE recognized $29.2 million, 2003 January 1, Acquired Other(a) December 31, during 2002.
(In millions) The following is our, and BGE's, estimated amortization Goodwill $118.2 $27.5 $ 0.6 $146.3 expense for 2005 through 2009 for the intangible assets included (a) Other represents purchase price adjustments in our, and BGE's, Consolidated Balance Sheets at December 31, 2004:
Goodwill is not amortized, rather it is evaluated for impairment at least annually. We evaluated our goodwill in 2004 Year Ended December 31, 2005 2006 2007 2008 2009 and determined that it was not impaired. For tax purposes, (In milions)
$115.7 million of our goodwill balance is deductible. Estimated amortization expense-Nonregulated businesses S53.6 $51.9 $36.1 $31.2 $27.8 Intangible Assets Subject to Amortization Estimated amortization expense-Intangible assets with finite lives are subject to amortization over BGE 31.0 22.4 22.1 21.4 21.2 their estimated useful lives. The primary assets included in this Total estimated amortization expense-Constellation Energy $84.6 $74.3 $58.2 $52.6 $49.0 category are as follows:
At Derember31. 2004 2003 Accumul- Accumul-Gross ated Gross ated Carrying Amortiz- Net Carrying Amortiz- Net Amount ation Asset Amount ation Asset (In millions)
Sofiware $388.4 $205.4 $183.0 $285.6 $155.1 $130.5 Acquired energy contracts (net) 185.2 84.8 100.4 182.5 36.7 145.8 Permits and licenses 37.7 5.7 32.0 28.8 3.2 25.6 Operating manuals and procedures 38.6 4.5 34.1 12.5 2.7 9.8 Other 20.0 12.1 7.9 22.6 10.7 11.9 Total $669.9 $312.5 $357.4 $532.0 $208.4 $323.6 BGE recorded intangible astis with a gross carrying amount of $253.1 million and acmulated amortization of 161.2 million in 2004 and a gzrs carrying amount of $212.2 million and acumulated amortization of
$1273 milion in 2003 and are included in the table above. Substanitally all of AGEs intangible assts: rlate to soft ware.
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6 Regulatory Assets (net)
As discussed in Note 1, the Maryland PSC and the FERC A portion of this regulatory asset represents the provide the final determination of the rates we charge our decommissioning and decontamination fund payment for federal customers for our regulated businesses. Generally, we use the uranium enrichment facilities that do not earn a return on the same accounting policies and practices used by nonregulated rate base investment. These amounts were $10.5 million at companies for financial reporting under accounting principles December 31, 2004 and $13.4 million at December 31, 2003.
generally accepted in the United States of America. However, Prior to the deregulation of electric generation, these costs were sometimes the Maryland PSC or FERC orders an accounting recovered through the electric fuel rate mechanism, and were treatment different from that used by nonregulated companies to excluded from rate base. We will continue to amortize this determine the rates we charge our customers. WVhen this amount through 2008.
happens, we must defer certain regulated expenses and income in our Consolidated Balance Sheets as regulatory assets and Net Cost of Removal liabilities. We then record them in our Consolidated Statements As discussed in Note 1, we use the composite depreciation of Income (using amortization) when we include them in the method for the regulated business. This method is currently an rates we charge our customers. acceptable method of accounting under accounting principles We summarize regulatory assets and liabilities in the generally accepted in the United States of America and is widely following table, and we discuss each of them separately below. used in the energy, transportation, and telecommunication industries.
At December 31, 2004 2003 Historically, under the composite depreciation method, the (In millions) anticipated costs of removing assets upon retirement were Electric generation-related regulatory asset $ 192.4 $ 211.3 provided for over the life of those assets as a component of Net cost of removal (132.5) (147.8) depreciation expense. However, effective January 1, 2003, we Income taxes recoverable through future adopted SFAS No. 143, Accountingfor Asse Retirement rates (net) 74.9 81.8 Obligations. In addition to providing the accounting Deferred postretirement and requirements for recognizing an estimated liability for legal postemployment benefit costs 25.8 29.0 obligations associated with the retirement of tangible long-lived Deferred environmental costs 17.6 20.4 assets, SFAS No. 143 precludes the recognition of expected net Deferred fuel costs (net) 5.9 11.9 future costs of removal as a component of depreciation expense Workforce reduction costs 14.1 21.2 Other (net) (2.8) 1.7 or accumulated depreciation.
BGE is required by the Maryland PSC to use the Total regulatory assets (net) $ 195.4 $ 229.5 composite depreciation method, including cost of removal, under regulatory accounting. In accordance with SFAS No. 71, BGE Electric Generation-Related Regulatory Asset continues to accrue for the future cost of removal for its As a result of the deregulation of electric generation, BGE does regulated gas and electric assets by increasing its regulatory not meet the requirements for the application of SFAS No. 71 liability. This liability is relieved when actual removal costs are for the electric generation portion of its business. In accordance incurred.
with SFAS No. 101, Regulated Enterprises-Accountingforthe Discontinuationof Application of FASB Statement No. 71, and Income Taxes Recoverable Through Future Rates (net)
EITF 97-4, Deregulation of the Pricing ofFlectricity-Issues As described in Note 1, income taxes recoverable through future Related to the Application of FASB Statements No. 71 and 101. all rates are the portion of our net deferred income tax liability that individual generation-related regulatory assets and liabilities must is applicable to our regulated business, but has not been reflected be eliminated from our balance sheet unless these regulatory in the rates we charge our customers. These income taxes assets and liabilities will be recovered in the regulated portion of represent the tax effect of temporary differences in depreciation the business. BGE wrote-off all of its individual, generation- and the allowance for equity funds used during construction, related regulatory assets and liabilities. BGE established a single, offset by differences in deferred tax rates and deferred taxes on new generation-related regulatory asset for amounts to be deferred investment tax credits. We amortize these amounts as collected through its regulated transmission and distribution the temporary differences reverse.
business. The new regulatory asset is being amortized on a basis that approximates the pre-existing individual regulatory asset amortization schedules.
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Deferred Postretirement and Postemployment Benefit In December 2002, a Hearing Examiner from the Costs Maryland PSC issued a proposed order related to our annual gas Deferred postretirement and postemployment benefit costs are adjustment clause review disallowing $7.7 million of a previously the costs we recorded under SFAS No. 106, Employers established regulatory asset of $9.4 million for certain credits Accountingfor PosttretmentBenefits Other Than Pensions, and that were over-refunded to customers through our market-based SFAS No. 112. Employers'Accountingfor Posremployment Benefits rates. BGE reserved the $7.7 million as disallowed fuel costs in in excess of the costs we included in the rates we charge our the fourth quarter of 2002. In August 2003, the Maryland PSC customers. We began amortizing these costs over a 15-year issued an order authorizing us to recover the $7.7 million and period in 1998. we reinstated the $9.4 million regulatory asset.
We exclude gas deferred fuel costs from rate base because Deferred Environmental Costs their existence is relatively short-lived. These costs are recovered Deferred environmental costs are the estimated costs of in the following year through our gas cost adjustment clauses.
investigating and cleaning up contaminated sites we own. We discuss this further in Note 12. We are amortizing $21.6 million Workforce Reduction Costs of these costs (the amount we had incurred through The portions of the costs associated with our VSERP and October 1995) and $6.4 million of these costs (the amount we workforce reduction programs that relate to BGE's gas business incurred from November 1995 through June 2000) over 10-year are deferred as regulatory assets in accordance with the Maryland periods in accordance with the Maryland PSCs orders. PSC's orders in prior rate cases. These costs are amortized over 5-year periods.
Deferred Fuel Costs As described in Note 1, deferred fuel costs are the difference between our actual costs of natural gas and our fuel rate revenues collected from customers. We reduce deferred fuel costs as we collect them from or refund them to our customers.
7 Penslon, Postretirement, Other Postemployment, and Employee Savings Plan Benefits We offer pension, postretirement, other postemployment, and We fund the qualified plans by contributing at least the employee savings plan benefits. BGE employees participate in minimum amount required under Internal Revenue Service the benefit plans that we offer. We describe each of our plans (IRS) regulations. We calculate the amount of funding using an separately below. Nine Mile Point offers its own pension, actuarial method called the projected unit credit cost method.
postretirement, other postemployment, and employee savings The assets in all of the plans at December 31, 2004 and 2003 plan benefits to its employees. The benefits for Nine Mile Point were mostly marketable equity and fixed income securities.
are included in the tables beginning on the next page.
We use a December 31 measurement date for our pension, Postretirement Benefits postretirement, other postemployment, and employee savings Wede sponsor defined benefit postretirement health care and life plans. insurance plans that cover the vast majority of our employees.
Generally, we calculate the benefits under these plans based on Pension Benefits age, years of service, and pension benefit levels or final base pay.
We sponsor several defined benefit pension plans for our We do not fund these plans.
employees. These include basic qualified plans that most For nearly all of the health care plans, retirees make employees participate in and several nonqualified plans that are contributions to cover a portion of the plan costs.
available only to certain employees. A defined benefit plan Contributions for employees who retire after June 30, 1992 specifies the amount of benefits a plan participant is to receive are calculated based on age and years of service. The amount of using information about the participant. Employees do not retiree contributions increases based on expected increases in contribute to these plans. Generally, we calculate the benefits medical costs. For the life insurance plan, retirees do not make under these plans based on age, years of service, and pay. contributions to cover a portion of the plan costs.
Sometimes we amend the plans retroactively. These Effective in 2002, we amended our postretirement medical retroactive plan amendments require us to recalculate benefits plans for all subsidiaries other than Nine Mile Point. Our related to participants' past service. Weze amortize the change in contributions for retiree medical coverage for future retirees that the benefit costs from these plan amendments on a straight-line were under the age of 55 on January 1, 2002 are capped at the basis over the average remaining service period of active 2002 level. WVe also amended our plans to increase the Medicare employees. eligible retirees' share of medical costs.
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In 2003, the President signed into law the Medicare As required under SPAS No. 87, we recorded additional Prescription Drug Improvement and Modernization Act of 2003 minimum pension liability adjustments as follows:
(the Act). This legislation provides a prescription drug benefit for Medicare beneficiaries, a benefit that we provide to our Increase (Decrcasc)
Medicare eligible retirees. Our actuaries concluded that Accumulated Other prescription drug benefits available under our postretirement Pension Comprehensive medical plan are currently "actuarially equivalent" to Medicare Liability Intangible Income (Loss)
Adjustment Asset
- Pre-tax After-tat Part D and thus qualify for the subsidy under the Act. This (In millions) conclusion requires that we meet both the 'gross test" and 'net 2001 5133.0 $59.0 $ (74.0) $ (44.7) test" regulations. Our prescription drug plan provides a higher 2002 189.5 (5.8) (195.3) (118.1) level of benefits than Medicare Part D, thereby satisfying the 2003 (27.3) (6.5) 20.8 12.6 "gross test". Our share of these costs exceeds that of Medicare 2004 64.4 (6.1) (70.5) (42.6)
Part D. thereby satisfying the 'net test" method. Total $359.6 $40.6 $(319.0) 5(192.8)
The expected subsidy will offset or reduce our share of the cost of the underlying postretirement prescription drug coverage. Included in "Other assets' in our ConsolidatedBalance Sheets.
I The estimated impact of this legislation reduced our Accumulated Postretirement Benefit Obligation by $30.6 million Obligations, Assets, and Funded Status at January 1, 2004 and our annual postretiremenr benefit In June 2004, we assumed pension and postretirement benefit expense in 2004 by $4.0 million. Final implementation guidance obligations for new employees in connection with the acquisition was issued in January 2005. This guidance will not have a of the RE. Ginna Nuclear Plant (Ginna). The sellers of Ginna material impact on our estimated impact of this legislation. This transferred assets into our qualified plan trust. We discuss the subsidy will reduce estimated 2006 cash per capita medical costs Ginna acquisition further in Note 15. As a result of a workforce from $3,199 to $2,671, or 17%. reduction initiative in the generation business, pension and postretirement special termination benefits were recorded in Additional Minimum Pension Liability Adjustment December 2004. We discuss the workforce reduction initiative Our pension accumulated benefit obligation has exceeded the further in Mote 2. We show the change in the benefit fair value of our plan assets since 2001. At December 31, 2004 obligations, plan assets, and funded status of the pension and and 2003. our pension obligations were greater than the fair postretirement benefit plans in the following tables.
value of our plan assets for our qualified and our nonqualified pension plans as follows: PensiocI Postretiremcnt Benefit as Benefits Qualified Plans Non-Qualified 2004 2003 2004 2003 At Derem6er31, 2004 Nine Mile Other Plans Total (In millions)
(In millions) Change in benefit obligation Accumulated benefit Benefit obligation at obligation $122.1 $1,185.9 $46.1 $1,354.1 January 1 $1,326.0 $1,247.5 $430.8 5415.4 Fair value of assets 78.6 1,005.8 - 1,084.4 Service cost 40.1 33.7 6.5 6.1 Interest cost 82.4 81.3 22.6 26.3 Unfunded obligation $ 43.5 $ 180.1 $46.1 $ 269.7 Plan participans contributions - - 5.8 6.1 Qualified Plans Non-Qualified Actuarial loss (gain) 117.1 76.0 (17.2) 11.4 At Decrmaer31, 2003 Nine Mile Other Plans Total Plan amendments - (0.4) - -
Ginna acquisition 40.5 - 6.1 -
(In millions)
Special termination benefits 2.4 - 1.2 -
Accumulated benefit Benefits paid (1) (95.3) (112.1) (32.6) (34.5) obligation 598.3 $1,044.9 $37.1 S1,180.3 Fair value of assets 66.7 887.9 - 954.6 Benefit obligation at December 31 $1,513.2 $1,326.0 $423.2 5430.8 Unfunded obligation 531.6 $ 157.0 $37.1 $ 225.7 (l) Benefits paid include annuity payments, lump-sum distributions, and transfers to nonqualified deferred compensation plans.
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Pension Postretirement We show the components of net periodic postretirement Benefits Benefits benefit cost in the following table:
2004 2003 2004 2003 (In millions) Year Ended December 31, 2004 2003 2002 Change in plan assets (In millions)
Fair value of plan assets at January 1 $ 954.6 S 767.7 $ - S Components of net periodic postretirement Actual return on plan assets 114.1 183.6 benefit cost Employer contribution 60.2 115.4 26.7 28.4 Service cost $ 6.5 $ 6.1 $ 5.0 Plan participants' contributions - - 5.9 6.1 Interest cost 22.6 26.3 26.7 Ginna acquisition 50.8 - - - Amortization of transition obligation 2.1 2.1 2.1 Benefits paid (1) (95.3) (112.1) (32.6) (34.5) Recognized net actuarial loss 3.1 5.8 6.4 Amortization of unrecognized prior service Fair value of plan assets at cost (3.5) (3.5) (3.5)
December 31 $1,084.4 S 954.6 S - S Amount capitalized as construction cost (7.0) (8.8) (9.1)
(1) Benefits paid include annuity payments, lump-sum distributions, and Net periodic postretirement benefit cost (1) $23.8 $28.0 $27.6 transfers to nonqualified deferred compensation plans.
(1) Net periodic postretirement benefit cost excludes SFAS No. 106 termination benefits of $1.2 million in 2004 and $9.2 million in Pension Postretirement 2002. BGE's portion of our net periodic postretirement benefit cost Benefits Benefits was $15.1 million in 2004. $19.4 million in 2003. and At December 31. 2004 2003 2004 2003 $21.1 million in 2002.
(In millios)
Funded Status Expected Cash Benefit Payments Funded Status S(428.8) $(371.4) 5(423.2) $(430.8) The pension and postretirement benefits we expect to pay in Unrecognized net actuarial loss 480.8 397.0 121.1 140.6 Unrecognized prior service cost 37.9 43.9 (36.7) (40.2) each of the next five calendar years and in the aggregate for the Unrecognized transition subsequent five years are shown below. These estimated benefits obligation - - 17.0 19.2 are based on the same assumption used to measure the benefit Pension liability adjustment (359.6) (295.2) - - obligation at December 31, 2004. but includes benefits Accrued benefit cost 5(269.7) $(225.7) $(321.8) $(311.2) attributable to estimated future employee service.
Net Periodic Benefit Cost Postretirement Benefits We show the components of net periodic pension benefit cost in Before After the following table: Pension Medicare Medicare Benefits Part D Subsidy Part D Year Ended December 31, 2004 2003 2002 (In millions)
(In millions) 2005 $ 90.6 $ 26.5 $ - $ 26.5 Components of net periodic pension 2006 83.0 28.2 2.1 26.1 benefit cost 2007 85.5 29.6 2.3 27.3 Service cost S 40.1 $ 33.7 S 29.6 2008 87.9 30.4 2.4 28.0 Interest cost 82.3 81.3 82.2 Expected return on plan assets (97.9) (95.0) (91.0) 2009 92.1 31.1 2.6 28.5 Amortization of unrecognized prior service 2010-2014 553.3 164.4 14.4 150.0 cost 5.8 5.8 6.7 Recognized net actuarial loss 14.3 5.0 1.3 Assumptions Amount capitalized as construction cost (4.5) (2.6) (2.9) We made the assumptions below to calculate our pension and Net periodic pension benefit cost (1) $ 40.1 $ 28.2 $ 25.9 postretircment benefit obligations and periodic cost.
(1) Net periodic pension benefit cost excludes SFAS No. 88 settlement charge of $2.8 million and termination benefits of $2.4 million in Pension Postretirement Assumption 2004, SFAS No. 88 settlement charge of $2.8 million in 2003, and Benefits Benefits Impacts SFAS No. 88 settlement charge of $29.6 million and termination 2004 2003 2004 2003 Calculation of benefits of $43.0 million in 2002. BGE's portion of our net periodic pension benefit costs was $8.6 million in 2004. $4.3 million in Benefit 2003. and $5.0 million in 2002. Obligation and Discount rate 5.75% 6.25% 5.75% 6.25% Periodic Cost Expected return on plan assets 9.0 9.0 N/A N/A Periodic Cost Rate of Benefit compensation Obligation and increase 4.0 4.0 4.0 4.0 Periodic Cost Our 9.0% overall expected long-term rate of return on plan assets reflects our long-term investment strategy in terms of asset mix targets and expected returns for each asset class.
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Annual health care inflation rate assumpt:ions also impact Contributions and Benefit Payments the calculation of our postretirement benefit cObligation and We contributed an additional $50 million to our qualified periodic cost. We assumed the following healt h care inflation pension plans in March 2005, even though there is no IRS rates to produce average claims by year as sho' wn below: required minimum contribution in 2005.
Our non-qualified pension plans and our postretirement At December 31, 2004 2003 benefit programs are not funded. We estimate that we will incur approximately $2.7 million in pension benefits for our Next year 10.0% 8.0% non-qualified pension plans and approximately $26.5 million Following year 9.0% 6.0% for retiree health and life insurance costs during 2005.
Ultimate trend rate 5.0% 5.0%
--A--
Year ultimate trend rate reached ZUIU ZUIU Other Postemployment Benefits We provide the following postemployment benefits:
A one-percent increase in the health care inflation rate
- health and life insurance benefits to eligible employees from the assumed rates would increase the acc umulated determined to be disabled under our Disability postretirement benefit obligation by approximaitely Insurance Plan,
$31.9 million as of December 31, 2004 and ,'ould increase the
- income replacement payments for Nine Mile Point combined service and interest costs of the post retirement union-represented employees determined to be benefit cost by approximately $2.0 million anp ually. disabled, and A one-percent decrease in the health care inflation rate
- income replacement payments for other employees from the assumed rates would decrease the accumulated determined to be disabled before November 1995 postretirement benefit obligation by approxima.tely (payments for employees determined to be disabled
$26.9 million as of December 31, 2004 and .'ould decrease after that date are paid by an insurance company, and the combined service and interest costs of the postretirement the cost is paid by employees).
benefit cost by approximately $1.7 million ant iually. The liability for these benefits totaled $53.5 million as of December 31, 2004 and $50.6 million as of December 31, Qualified Pension Plan Assets 2003.
The asset allocations for our qualified pension plans were as We assumed the discount rate for other postemployment follows: benefits to be 5.0% in 2004 and 5.25% in 2003. This assumption impacts the calculation of our other At December 31, 2004 2003 postemployment benefit obligation and periodic cost.
Equity securities 57% 56%
Debt securities 33 32 Employee Savings Plan Benefits Other 10 12 We sponsor defined contribution savings plans that are offered 100% 100% to all eligible employees. The savings plans are qualified 401(k)
Total plans under the Internal Revenue Code. In a defined The category "Other" primarily represents investments in contribution plan, the benefits a participant is to receive result financial limited partnerships. Our long-term ppension plan from regular contributions to a participant account. Matching investment strategy is to seek an asset mix of 553% equity, 35% contributions to participant accounts are made under these fixed income, and 12% other investments. We rebalance our plans. Matching contributions to these plans were:
portfolio periodically when the sum of equity and other * $16.7 million, of which BGE contributed investments differs from 65% by three percent age points or $4.7 million, in 2004, more, we change an outside investment advisor or we make * $14.1 million, of which BGE contributed contributions to the trust. $4.6 million, in 2003, and
- $13.3 million, of which BGE contributed
$4.9 million, in 2002.
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8 Credit Facilities and Short-Term Borrowings Our short-term borrowings may include bank loans, commercial BGE paper, and bank lines of credit. Short-term borrowings mature BGE had no commercial paper outstanding at December 31, within one year from the date of issuance. We pay commitment 2004 and 2003.
fees to banks for providing us lines of credit. When we borrow During 2004, certain credit facilities expired and BGE under the lines of credit, we pay market interest rates. renewed those facilities. BGE continues to maintain
$200.0 million in committed credit facilities, expiring May 2005 Constellation Energy through November 2005. BGE can borrow directly from the Constellation Energy had committed bank lines of credit under banks or use the facilities to allow the issuance of commercial four credit facilities of $2.2 billion at December 31, 2004 for paper.
short-term financial needs as follows:
- $640.0 million three-year revolving credit facility Other Nonregulated Businesses expiring in June 2005, Our other nonregulated businesses had no short-term borrowings
- $447.5 million three-year revolving credit facility outstanding at December 31, 2004 and $9.6 million at expiring in June 2006, December 31, 2003. The weighted-average effective interest rates
- $800.0 million three-year revolving credit facility for our other nonregulated businesses' short-term borrowings expiring in June 2007, and were 3.11% at December 31, 2003.
- $300.0 million five-year revolving credit facility expiring in June 2009, We use these facilities to allow issuance of commercial paper and letters of credit primarily for our merchant energy business. These facilities can issue letters of credit up to approximately $2.2 billion. Letters of credit issued under all of our facilities totaled $809.9 million at December 31, 2004 and
$507.1 million at December 31, 2003. Constellation Energy had no commercial paper outstanding at December 31, 2004 and 2003.
9 Long-Term Debt and Preference Stock Long-term Debt In connection with the sale of our geothermal generating Long-term debt matures in one year or more from the date of facility in Hawaii, we repaid prior to maturity $43.3 million of issuance. We detail our long-term debt in our Consolidated long-term debt. We discuss the sale of this facility in more detail Statements of Capitalization. As you read this section, it may be in Note 2.
helpful to refer to those statements.
BGE Constellation Energy BGE! First Ref snding Mortgage Bonds During 2004, we decided to continue our ownership in a BGE's first refunding mortgage bonds are secured by a mortgage synthetic fuel processing facility in South Carolina. We discuss lien on all of its assets. The generating assets BGE transferred to this facility in more detail in Note 10. In connection with our subsidiaries of Constellation Energy also remain subject to the decision to continue with our ownership in this facility, we are lien of BGE's mortgage, along with the stock of Safe Harbor committed to making fixed payments until the end of 2007. Water Power Corporation and Constellation Enterprises, Inc.
Accordingly, during 2004, we recorded a liability of
$39.3 million, net of discount related to imputed interest, in
'Long-term debt" in our Consolidated Balance Sheets for these fixed payments. We used an imputed interest rate because there was no stated interest rate on these fixed payments. The imputed interest rate was calculated to be 3.47% and was based on our borrowing rate for a similar loan.
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BGE is required to make an annual sinking fund payment BGE Deferrable Interest Subordinated Debentures each August I to the mortgage trustee. The amount of the On November 21, 2003, BGE Capital Trust 11 (BGE Trust 11),
payment is equal to 1% of the highest principal amount of a Delaware statutory trust established by BGE, issued bonds outstanding during the preceding 12 months. The trustee 10,000,000 Trust Preferred Securities for $250 million ($25 uses these funds to retire bonds from any series through liquidation amount per preferred security) with a distribution repurchases or calls for early redemption. However, the trustee rate of 6.20%.
cannot call the following bonds for early redemption: BGE Trust II used the net proceeds from the issuance of
- 71/z% Series, due 2007 common securities to BGE and the Trust Preferred Securities to
- 6'/a% Series, due 2008 purchase a series of 6.20% Deferrable Interest Subordinated Holders of the Remarketed Floating Rate Series due Debentures due October 15, 2043 (6.20% debentures) from September 1, 2006 have the option to require BGE to BGE in the aggregate principal amount of $257.7 million with repurchase their bonds at face value on September I of each the same terms as the Trust Preferred Securities. BGE Trust 11 year. BGE is required to repurchase and retire at par any bonds must redeem the Trust Preferred Securities at $25 per preferred that are not remarketed or purchased by the remarketing agent. security plus accrued but unpaid distributions when the 6.20%
BGE also has the option to redeem all or some of these bonds debentures are paid at maturity or upon any earlier redemption.
at face value each September 1. BGE has the option to redeem the 6.20% debentures at any During 2004, BGE called $4.8 million principal amount of time on or after November 21, 2008 or at any time when its Remarketed Floating Rate Series due September 1, 2006 to certain tax or other events occur.
satisfy the sinking fund requirement under the First Refunding BGE Trust 11 will use the interest paid on the 6.20%
Mortgage Bond indenture. These bonds were redeemed in whole debentures to make distributions on the Trust Preferred or in part at the sinking fund call price of 100% of principal Securities. The 6.20% debentures are the only assets of BGE amount plus accrued interest from June 1, 2004 to, but not Trust I.
including, August 25, 2004. BGE fully and unconditionally guarantees the Trust Preferred Securities based on its various obligations relating to BGE! Other Long-Term Debt the trust agreement, indentures, 6.20% debentures, and the On July 1, 2000, BGE transferred $278.0 million of tax-exempt preferred security guarantee agreement.
debt to our merchant energy business related to the transferred For the payment of dividends and in the event of assets. At December 31, 2004, BGE remains contingently liable liquidation of BGE, the 6.20% debentures are ranked prior to for the $269.8 million outstanding balance of this debt. preference stock and common stock.
We show the weighted-average interest rates and maturity At December 31, 2003, we applied the provisions of FIN dates for BGE's fixed-rate medium-term notes outstanding at 46R as it relates to special purpose entities. FIN 46R establishes December 31, 2004 in the following table. conditions under which an entity must be consolidated based upon variable interests rather than voting interests. FIN 46R Weighted-Average Maturity requires us to consolidate variable interest entities for which we Series Interest Rate Dates are the primary beneficiary. Therefore, at December 31, 2003, B 8.63% 2006 we and BGE deconsolidated BGE Trust II because BGE is not D 6.62 2005-2006 its primary beneficiary. As a result, we and BGE removed the E 6.66 2006-2012 Trust Preferred Securities from our and BGE's Consolidated G 6.08 2008 Balance Sheets and from our Consolidated Statements of Some of the medium-term notes include a "put option." Capitalization as of December 31, 2003. At December 31, 2004 These put options allow the holders to sell their notes back to and 2003, we and BGE recorded the $257.7 million of 6.20%
BGE on the put option dates at a price equal to 100% of the Deferrable Interest Subordinated Debentures due to BGE Trust principal amount. The following is a summary of medium-term 11 and recorded our and BGE's $7.7 million equity investment notes with put options. in BGE Trust II in "Other assets" in our and BGE's Consolidated Balance Sheets. We discuss FIN 46R in more Series E Notes Principal Put Option Dates detail in Accounting Standards Adopted section in Note 1.
(In millions) 6.75%, due 2012 $59.5 June 2007 Other NionregulatedBusinesses 6.75%, due 2012 25.0 June 2007 In 2004, we terminated certain loans under other revolving 6.73%, due 2012 25.0 June 2007 credit agreements of $41.4 million related to our Panamanian distribution facility. We replaced these revolving credit agreements with loans under new revolving credit agreements totaling $100.0 million.
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Revolving Credit Agreement Maturities of Long-Term Debt On December 18, 2001, ComfortLink entered into a All of our long-term borrowings mature on the following
$25.0 million loan agreement with the Maryland Energy schedule (includes sinking fund requirements):
Financing Administration (MEFA). The terms of the loan exactly match the terms of variable rate, tax exempt bonds due Constellation Nonregulated Year Energy Businesses BGE December 1, 2031 issued by MEFA for ComfortLink to finance (In millioni) the cost of building a chilled water distribution system. The 2005 $ 300.0 S 14.5 S 41.6 interest rate on this debt resets weekly. These bonds, and the 2006 - 20.1 442.9 corresponding loan, can be redeemed at any time at par plus 2007 600.0 19.5 122.4 accrued interest while under variable rates. The bonds can also 2008 - 8.3 296.0 be converted to a fixed rate at ComfortLink's option. 2009 500.0 10.0 11.5 Thereafter 1,963.3 364.8 589.2 Debt Compliance and Covenants Total long-term debt at The credit facilities of Constellation Energy and BGE have December 31. 2004 53,363.3 $437.2 $1,503.6 limited material adverse change clauses that only consider a material change in financial condition and are not directly At December 31, 2004, we had long-term loans totaling affected by decreases in credit ratings. If these clauses are $381.6 million that mature after 2004 which contain certain put invoked, the lending institutions can dedine making new options under which lenders could potentially require us to advances or issuing new letters of credit, but cannot accelerate repay the debt prior to maturity. At December 31, 2004, existing amounts outstanding. The long-term debt indentures of $124.3 million is classified as current portion of long-term debt Constellation Energy and BGE do not contain material adverse as a result of these provisions.
change clauses or financial covenants.
Certain credit facilities of Constellation Energy contain a Weighted-Average Interest Rates for Variable Rate Debt provision requiring Constellation Energy to maintain a ratio of Our weighted-average interest rates for variable rate debt were:
debt to capitalization equal to or less than 65%. At December 31, 2004, the debt to capitalization ratio as defined At Deetmber31. 2004 2003 in the credit agreements was no greater than 51%. Nonregulated Businesres (including Constellation Energy)
Certain credit agreements of BGE contain provisions Loans under credit agreements 3.58% 3.98%
requiring BGE to maintain a ratio of debt to capitalization equal Tax-exempt debt transferred from BGE 1.54 1.40 to or less 65%. At December 31, 2004, the debt to BGE capitalization ratio for BGE as defined in these credit agreements Remarketed floating rate series mortgage bonds 1.39% 1.29%
was 46%. At December 31, 2004, no amounts were outstanding under these agreements.
As discussed in Note 13 we have entered into interest rate Failure by Constellation Energy, or BGE, to comply with swaps relating to $450 million of our fixed-rate debt.
these covenants could result in the maturity of the debt outstanding under these facilities being accelerated. The credit Preference Stock facilities of Constellation Energy contain usual and customary Each series of BGE preference stock has no voting power, except cross-default provisions that apply to defaults on debt by for the following:
Constellation Energy and certain subsidiaries over a specified
- the preference stock has one vote per share on any threshold. Certain BGE credit facilities also contain usual and charter amendment which would create or authorize any customary cross-default provisions that apply to defaults on debt shares of stock ranking prior to or on a parity with the by BGE over a specified threshold. The indentures pursuant to preference stock as to either dividends or distribution of which BGE has issued and outstanding mortgage bonds and assets, or which would substantially adversely affect the subordinated debentures provide that a default under any debt contract rights, as expressly set forth in BGE's charter, instrument issued under the relevant indenture may cause a of the preference stock, each of which requires the default of all debt outstanding under such indenture.
affirmative vote of two-thirds of all the shares of Constellation Energy also provides credit support to Calvert preference stock outstanding; and Cliffs, Ginna, and Nine Mile Point to ensure these plants have
- whenever'BGE fails to pay full dividends on the funds to meet expenses and obligations to safely operate and preference stock and such failure continues for one year, maintain the plants. the preference stock shall have one vote per share on all matters, until and unless such dividends shall have been paid in full. Upon liquidation, the holders of the preference stock of each series outstanding are entitled to receive the par amount of their shares and an amount equal to the unpaid accrued dividends.
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1 0 Taxes The components of income tax expense are as follows:
Year Ended December 31. 2004 2003 2002 (Dollaramounts in millions)
Income Taxes Current Federal $ 33.9 $134.0 $145.0 State 22.1 33.6 24.2 Current taxes charged to expense 56.0 167.6 169.2 Deferred Federal 98.5 93.2 131.2 State 24.9 16.0 17.1 Deferred taxes charged to expense 123.4 109.2 148.3 Investment tax credit adjustments (7.2) (7-3) (7.9)
Income taxes per Consolidated Statements of Income $172.2 $269.5 $309.6 Total income taxes are different from the amount that would be computed by applying the statutory Federal income tax rate of 35% to book income before income taxes as follows:
Reconciliation of Income Taxes Computed at Statutory Federal Rate to Total Income Taxes Income before income taxes (exduding BGE preference stock dividends) $774.2 $758.4 $848.4 Statutory federal income tax rate 35% 35% 35%
Income taxes computed at statutory federal rate 271.0 265.4 296.9 Inaeases (decreases) in income taxes due to Depreciation differences not normalized on regulated activities 4.0 4.1 4.8 Amortization of deferred investment tax credits (7.2) (7.3) (7.9)
Synthetic fuel tax credits flowed through to income (123.2) (35.0) (20.7)
State income taxes, net of federal income tax benefit 30.0 34.1 31.4 Other (2.4) 8.2 5.1 Total income taxes $172.2 S269.5 $309.6 Effective income tax rate 22.2% 35.5% 36.5%
BGE's effective tax rate was 38.1% in 2004. 39.2% in 2003, and 39.5% in 2002. The difference between BGE's effective tax rate and the 35% statutory federal income tax rate is primarily related to Maryland corporate income taxes at an effective rate of 4.55%, which is net of the related federal income tax benefit.
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The major components of our net deferred income tax liability are as follows:
Constellation Energy BGE At December 31, 2004 2003 2004 2003 (In milliom)
Deferred Income Taxes Deferred tax liabilities Net property, plant and equipment $1,522.7 $1,373.0 $ 540.5 $ 501.4 Qualified nuclear decommissioning trust funds 317.6 252.6 - -
Regulatory assets, net 95.1 105.7 95.1 105.7 Mark-to-market energy assets and liabilities, net 83.7 72.6 -
Financial investments and hedging instruments - 39.9 -
Other 88.8 132.1 62.6 63.1 Total deferred tax liabilities 2,107.9 1,975.9 698.2 670.2 Deferred tax assets Asset retirement obligation 327.3 235.3 - -
Accrued pension and post-employment benefit costs 194.0 183.3 58.3 62.9 Financial investments and hedging instruments 103 - -
Deferred investment tax credits 26.9 27.4 5.9 6.5 Reduction of investments 46.4 40.4 -
Other 104.7 109.4 15.7 15.0 Total deferred tax assets 709.6 595.8 79.9 84.4 Total deferred tax liability, net 1,3983 1,380.1 618.3 585.8 Current portion of deferred tax liability, net-recorded in accrued expenses and other 95.0 68.3 10.3 9.6 Long-term portion of deferred tax liability, net $1,303.3 $1,311.8 $ 608.0 $ 576.2 Synthetic Fuel Tax Credits In 2003, we purchased 99% ownership in a South Our merchant energy business has investments in facilities that Carolina facility that produces synthetic fuel. We did not manufacture solid synthetic fuel produced from coal as defined recognize in our Consolidated Statements of Income the tax under Section 29 of the Internal Revenue Code for which we benefit of $35.9 million for credits daimed on our South can claim tax credits on our Federal income tax return through Carolina facility in 2003 pending receipt of a favorable private 2007. We recognize the tax benefit of these credits in our letter ruling. In 2004, we received a favorable private letter Consolidated Statements of Income when we believe it is ruling. We believe receipt of the private letter ruling provides highly probable that the credits will be sustained. The synthetic reasonable assurance that it is highly probable that the credits fuel process involves combining coal material with a chemical will be sustained. Therefore, we recognized the tax benefit of reagent to create a significant chemical change. A taxpayer may $35.9 million in our Consolidated Statements of Income request a private letter ruling from the IRS to support its during 2004.
position that the synthetic fuel produced undergoes a Under Section 29, only synthetic fuel sold before significant chemical change and thus qualifies for Section 29 January 1, 2008 can be claimed for synthetic fuel tax credits.
credits. Additionally. Section 29 provides for a phase-out of the tax As of December 31, 2004, we have recognized cumulative credit to the extent that average annual oil prices per barrel tax benefits associated with Section 29 credits of exceed an inflation adjusted oil price as determined annually by
$201.2 million, of which $123.2 million was recognized during the IRS. For 2005, we estimate that the credit reduction would the year ended December 31, 2004. begin if the average annual oil price per barrel exceeds We own a minority ownership in four synthetic fuel approximately $52 and would be fully phased out if the facilities located in Virginia and West Virginia. These facilities average annual oil price exceeds $65 per barrel.
have received private letter rulings from the IRS. In While we believe the production and sale of synthetic fuel January 2004, the IRS concluded its examination of the from all of our synthetic fuel facilities meet the conditions to partnership that owns these facilities for the tax years 1998 qualify for tax credits under Section 29 of the IRS Code, we through 2001 and the IRS did not disallow any of the cannot predict the timing or outcome of any future challenge previously recognized synthetic fuel credits. During the second by the IRS, legislative or regulatory action, oil prices, or the quarter of 2004, we received final written notice of the ultimate impact of such events on the Section 29 credits that resolution of the examination from the IRS. we have claimed to date or expect to daim in the future, but the impact could be material to our financial results.
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I I Leases There are two types of leases-operating and capital. Capital Lease expense was:
leases qualify as sales or purchases of property and are reported * $34.1 million in 2004, in our Consolidated Balance Sheets. Capital leases are not * $22.7 million in 2003, and material in amount. All other leases are operating leases and are * $19.4 million in 2002.
reported in our Consolidated Statements of Income. We expense At December 31, 2004, we owed future minimum all lease payments associated with our regulated business. Lease paymen'ts for long-term, noncancelable, operating leases as expense and future minimum payments for long-term, follows:
noncancelable, operating leases are not material to BGE's financial results. We present information about our operating Year leases below. (In millios) 2005 $113.2 Outgoing Lease Payments 2006 113.2 We, as lessee, lease some facilities and equipment. The lease 2007 106.0 agreements expire on various dates and have various renewal 2008 61.2 options. We also enter into certain power purchase agreements 2009 13.4 which are accounted for as operating leases. Under these Thereafter 127.9 agreements, we are required to make fixed capacity payments, as Total future minimum lease payments $534.9 well as variable payments based on actual output of the plants.
We exclude from our future minimum lease payments table the variable payments related to the output of the plant due to the contingency associated with these payments.
1 2 Commitments, Guarantees, and Contingencies Commitments Our regulated electric business enters into various long-term We have made substantial commitments in connection with our contracts for the procurement of electricity. These contracts merchant energy, regulated electric and gas, and other expire between 2005 and 2006. The cost of power under these nonregulated businesses. These commitments relate to: contracts are recoverable under the POLR agreement reached
- purchase of electric generating capacity and energy, with the Maryland PSC, as discussed in Note I and therefore are
- procurement and delivery of fuels, and excluded from the table on the next page.
- long-term service agreements, capital for construction Our regulated gas business enters into various long-term programs and other. contracts for the procurement, transportation, and storage of gas.
Our merchant energy business enters into various long-term Our regulated gas business has gas transportation and storage contracts for the procurement and delivery of fuels to supply our contracts that expire between 2005 and 2023. These contracts generating plant requirements. In most cases, our contracts are recoverable under BGE's gas cost adjustment clause discussed contain provisions for price escalations, minimum purchase in Note I and therefore are excluded from the table on the next levels, and other financial commitments. These contracts expire page.
in various years between 2005 and 2012. In addition, our Our other nonregulated business has committed to gas merchant energy business enters into long-term contracts for the purchases and to contributions of additional capital for capacity and transmission rights for the delivery of energy to construction programs and joint ventures in which they have an meet our physical obligations to our customers. These contracts interest.
expire in various years between 2005 and 2018. We have also committed to long-term service agreements Our merchant energy business also has committed to and other obligations related to our information technology long-term service agreements and other purchase commitments systems.
for our plants.
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At December 31, 2004. we estimate our future obligations
- Constellation Energy guaranteed $5,504.2 million on to be as follows: behalf of our subsidiaries for competitive supply activities. These guarantees are put into place in order Payments to allow our subsidiaries the flexibility needed to 2006- 2008- conduct business with counterparties without having to 2005 2007 2009 Thereafier Total (In millions) post substantial cash collateral. While the face amount Merchant Energy of these guarantees is $5,504.2 million, our calculated Purchased capacity and fair value of obligations covered by these guarantees was energy $ 794.2 S 743.3 $184.9 $157.0 S1,879.4 $1,395.6 million at December 31, 2004. If the parent Fuel and transportation 1.292.0 816.3 142.8 37.3 2.288.4 company was required to fund subsidiary obligations, Long-term service the total amount at current market prices is agreements. capital.
$1,395.6 million. The recorded fair value of obligations and other 59.3 47.2 70.0 208.6 385.1 in our Consolidated Balance Sheets for these guarantees Total merchant energy 2,145.5 1,606.8 397.7 402.9 4,552.9 was $781.1 million at December 31, 2004.
Corporate and Other:
- Constellation Energy guaranteed $945.6 million Long-term service agreements, capital, primarily on behalf of our nuclear generating facilities and other 25.4 12.2 3.1 1.9 42.6 primarily related to nuclear insurance and for credit Regulated: support to ensure these plants have funds to meet Purchase obligations expenses and obligations to safely operate and maintain and other 12.5 3.6 1.8 0.5 18.4 the plants.
Total future obligations $2,183.4 $1,622.6 $402.6 S405.3 $4,613.9
- Constellation Energy guaranteed $48.2 million on behalf of our other nonregulated businesses primarily for loans and performance bonds of which $25.0 million Long-Tern Power Sales Contracts was recorded in our Consolidated Balance Sheets at NWe enter into long-term power sales contracts in connection December 31, 2004.
with our load-serving activities. We also enter into long-term
- Our merchant energy business guaranteed $18.7 million power sales contracts associated with certain of our power plants.
for loans and other performance guarantees related to Our load-serving power sales contracts extend for terms through certain power projects in which we have an investment.
2012 and provide for the sale of full requirements energy to
- Our other nonregulated business guaranteed electricity distribution utilities and certain retail customers. Our
$11.2 million for performance bonds.
power sales contracts associated with our power plants extend for
- BGE guaranteed two-thirds of certain debt of Safe terms into 2014 and provide for the sale of all or a portion of Harbor Water Power Corporation, an unconsolidated the actual output of certain of our power plants. All long-term investment. At December 31, 2004, Safe Harbor Water contracts were executed at pricing that approximated market Power Corporation had outstanding debt of rates, including profit margin, at the time of execution.
$20 million. The maximum amount of BGE's guarantee is $13.3 million.
Guarantees
- BGE guaranteed the Trust Preferred Securities of The terms of our guarantees are as follows:
$250.0 million of BGE Trust II, an unconsolidated Expiration investment, as discussed in Note 9.
2006- 2008- The total fair value of the obligations for our guarantees 2005 2007 2009 Thereafter Total recorded in our Consolidated Balance Sheets was S806.1 million (In millioni) and not the $6.8 billion of total guarantees. We assess the risk Competitive Supply $3,693.4 $918.5 $314.5 $ 577.8 $5,504.2 of loss from these guarantees to be minimal.
Other 6.7 3.6 15.7 1,261.0 1,287.0 Total Guarantees $3.700.1 $922.1 $330.2 $1,838.8 $6,791.2 Environmental Matters Solid andHazardous Waste At December 31, 2004, Constellation Energy had a total of The Environmental Protection Agency (EPA) and several state
$6,791.2 million guarantees outstanding related to loans, credit agencies have notified us that we are considered a potentially facilities, and contractual performance of certain of its responsible party with respect to the clean-up of certain subsidiaries as described below. These guarantees do not environmentally contaminated sites. We cannot estimate the final represent our incremental obligations, and we do not expect to clean-up costs for all of these sites, but the costs and current fund the full amount under these guarantees. status of each site is described in more detail on the next page.
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AMetal Bank Spring Gardens In 1997, the EPA, under the Comprehensive Environmental In December 1996, BGE signed a consent order with the Response, Compensation and Liability Act ("Superfund"), issued Maryland Department of the Environment that requires it to a Record of Decision (ROD) for the proposed clean-up at the implement remedial action plans for contamination at and Metal Bank of America site, a metal redaimer in Philadelphia. around the Spring Gardens site, located in Baltimore, Maryland.
We had previously recorded a liability in our Consolidated The Spring Gardens site was once used to manufacture gas from Balance Sheets for BGE's 15.47% share of probable dean-up coal and oil. Based on the remedial action plans, BGE estimates costs. Based on current settlement negotiations among the EPA its probable clean-up costs will total S47 million. BGE has and the potentially responsible parties involved at the site, we do recorded these costs as a liability in its Consolidated Balance not believe we will incur clean-up costs in excess of the amount Sheets and has deferred these costs, net of accumulated recorded as a liability. The EPA and the potentially responsible amortization and amounts it recovered from insurance parties, including BGE, are currently pursuing claims against companies, as a regulatory asset. Based on the results of studies Metal Bank of America for an equitable share of expected site at this site, it is reasonably possible that additional costs could remediation costs. exceed the amount BGE has recognized by approximately
$14 million. Through December 31, 2004, BGE has spent 68th Street Dump approximately $40 million for remediation at this site.
In 1999, the EPA proposed to add the 68th Street Dump in BGE also has investigated other small sites where gas was Baltimore, Maryland to the Superfund National Priorities List manufactured in the past. We do not expect the dean-up costs
("NPL"), which is its list of sites targeted for dean-up and of the remaining smaller sites to have a material effect on our enforcement, and sent a general notice letter to BGE and 19 financial results.
other parties identifying them as potentially liable parties at the site. In March 2004, we and other potentially responsible parties Litigation formed the 68th Street Coalition, which has entered into In the normal course of business, we are involved in various consent order negotiations with the EPA to investigate dean-up legal proceedings. Wete discuss the significant matters below.
options for the site under the Superfund Alternative Sites Program. While negotiations under this program are ongoing, Western Power Mfarkets the 68th Street Dump will not be placed on the NPL At this Baldwin Associates. Inc. v. Gray Davis, Governor of California and stage, it is not possible to predict the outcome of those 22 other defendants (including ConstellationPower discussions or our share of the liability. However, the costs could Development, Inc., a subsidiary of Constellation Power Inc.)-This have a material effect on our financial results. putative dass action lawsuit was filed on October 5, 2001 in the Superior Court, County of San Francisco. The action requested Kane and Lombard damages, recession and reformation of approximately 38 The EPA issued its ROD for the Kane and Lombard Drum site long-term power purchase contracts, and an injunction against located in Baltimore, Maryland on September 30, 2003. The improper spending by the state of California.
ROD specifies the dean-up plan for the site, consisting of Constellation Power Development, Inc. was named as a enhanced reductive dechlorination, a soil management plan. and defendant but was never served with process in this case. On institutional controls. In July 2004, the EPA issued a Special December 6, 2004, the Court ordered dismissal of this action Notice/Demand Letter to BGE and three other potentially since the plaintiff had failed to serve the defendants.
responsible parties regarding implementation of the remedy. In response, the potentially responsible parties have proposed negotiations with the EPA regarding the implementation. The total clean-up costs are estimated to be approximately
$10 million. We estimate our current share of site-related costs to be 11.1%. In December 2002, we recorded a liability in our Consolidated Balance Sheets for our share of the dean-up costs that we believe is probable. Our final share of the $10 million has not been determined and it may vary from the current estimate.
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James M. Millar v. Allegheny Energy Supply, Constellation Power In a ruling applicable to all but several of the cases, the Source, Inc., High Desert Power Project, LLC, et al.,-On Circuit Court for Baltimore City dismissed with prejudice all December 19, 2003, plaintiffs filed an amended complaint in claims against BGE and Constellation Energy and entered a stay Superior Court of California, County of San Francisco, naming of the proceedings as they relate to other defendants. Plaintiffs for the first time, Constellation Power Source, Inc., renamed may attempt to pursue appeals of the rulings in favor of BGE Constellation Energy Commodities Group, Inc. (CCG), and and Constellation Energy once the cases are finally concluded as High Desert Power Project, LLC (High Desert), two of our to all defendants. We believe that we have meritorious defenses subsidiaries, as additional defendants. The complaint is a and intend to defend the actions vigorously. However, we cannot putative class action on behalf of California electricity consumers predict the timing or outcome of these cases, or their possible and alleges that the defendant power suppliers, including CCG effect on our, or BGE's, financial results.
and High Desert, violated California's Unfair Competition Law in connection with certain long-term power contracts that the Employment Discrimination defendants negotiated with the California Department of Water Miller et. al v. Baltimore Gas and Electric Company, et aL,-This Resources in 2001 and 2002. Notwithstanding the amended action was filed on September 20, 2000 in the U.S. District long-term power contracts and the releases and settlement Court for the District of Maryland. Besides BGE, Constellation agreements negotiated at the time of such amendments, the Energy Group, Constellation Nuclear, and Calvert Cliffs Nuclear plaintiff seeks to have the Court certify the case as a class action Power Plant are also named defendants. The action seeks class and to order the repayment of any monies that were acquired by certification for approximately 150 past and present employees the defendants under the long-term contracts or the amended and alleges racial discrimination at Calvert Cliffs Nuclear Power long-term contracts by means of unfair competition in violation Plant. The amount of damages is unspecified, however the of California law. We believe that we have meritorious defenses plaintiffs seek back and front pay, along with compensatory and to this action and intend to defend against it vigorously. punitive damages. The Court scheduled a briefing process for However, we cannot predict the timing, or outcome, of this case, the motion to certify the case as a class action suit. The briefing or its possible effect on our financial results. process concluded, oral argument on the class certification motion was held on April 16, 2004, and the parties are awaiting City of Tacoma v. AEI? et aL,-The City of Tacoma, on June 7, the court's decision. We do not believe class certification is 2004, in the U.S. District Court, Western District of appropriate and we further believe that we have meritorious Washington, filed a complaint against over 60 companies, defenses to the underlying claims and intend to defend the including CCG. The complaint alleges that the defendants action vigorously. However, we cannot predict the timing, or engaged in manipulation of electricity markets resulting in prices outcome, of the action or its possible effect on our, or BGE's, for power in the western power markets that were substantially above what market prices would have been in the absence of the financial results.
alleged unlawful contracts, combinations and conspiracy in violation of Section I of the Sherman Act. The complaint Asbestos further alleges that the total amount of damages is unknown, Since 1993, BGE has been involved in several actions but is estimated to exceed $175 million. On February 11, 2005, concerning asbestos. The actions are based upon the theory of the Court granted the defendants' motion to dismiss the action 'premises liability," alleging that BGE knew of and exposed based on the Court's lack of jurisdiction over the claims in individuals to an asbestos hazard. The actions relate to two types question. The plaintiff may seek to appeal the Court's dismissal of claims.
of the action. We believe that we have meritorious defenses to The first type is direct claims by individuals exposed to this action and intend to defend against it vigorously. However, asbestos. BGE is involved in these claims with approximately 70 we cannot predict the timing, or outcome, of this case, or its other defendants. Approximately 490 individuals that were never possible effect on our financial results. employees of BGE each claim $6 million in damages ($2 million compensatory and $4 million punitive). These claims are currently pending in state courts in Maryland and Pennsylvania.
Mercury BGE does not know the specific facts necessary to estimate its Beginning in September 2002, BGE, Constellation Energy, and potential liability for these claims. The specific facts BGE does several other defendants have been involved in numerous actions not know include:
filed in the Circuit Court for Baltimore City, Maryland alleging mercury poisoning from several sources, including coal plants
- the identity of BGE's facilities at which the plaintiffs allegedly worked as contractors, formerly owned by BGE. The plants are now owned by a
- the names of the plaintiffs employers, subsidiary of Constellation Energy. In addition to BGE and Constellation Energy, approximately 11 other defendants,
- the date on which the exposure allegedly occurred, and
- the facts and circumstances relating to the alleged consisting of pharmaceutical companies, manufacturers of vaccines, and manufacturers of Thimerosal have been sued. exposure.
To date, 351 asbestos cases were dismissed or resolved for Approximately 70 cases have been filed to date, with each case amounts that were not significant. Approximately 20 cases are seeking $90 million in damages from the group of defendants.
scheduled for trial through the end of 2006.
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The second type is claims by one manufacturer-Pittsburgh Nuclear Insurance Corning Corp. (PCC)-against BGE and approximately eight We maintain nuclear insurance coverage for Calvert Cliffs, Nine others, as third-parry defendants. On April 17, 2000, PCC Mile Point, and Ginna in four program areas: liability, worker declared bankruptcy. radiation, property, and accidental outage. These policies contain These claims relate to approximately 1,500 individual certain industry standard exclusions, including, but not limited plaintiffs and were filed in the Circuit Court for Baltimore City, to, ordinary wear and tear, and war.
Maryland in the fall of 1993. To date, about 375 cases have In November 2002, the President signed into law the been resolved, all without any payment by BGE. BGE does not Terrorism Risk Insurance Act ("TRIA") of 2002. Under the know the specific facts necessary to estimate its potential liability TRIA, property and casualty insurance companies are required to for these claims. The specific facts we do not know include: offer insurance for losses resulting from Certified acts of
- the identity of BGE facilities containing asbestos terrorism. Certified acts of terrorism are determined by the manufactured by the manufacturer, Secretary of State and Attorney General and primarily are based
- the relationship (if any) of each of the individual upon the occurrence of significant acts of international terrorism.
plaintiffs to BGE, Our nuclear property and accidental outage insurance programs,
- the settlement amounts for any individual plaintiffs who as discussed later in this section, provide coverage for Certified are shown to have had a relationship to BGE, acts of terrorism.
- the dates on which/places at which the exposure If there were an accident or an extended outage at any unit allegedly occurred, and of Calvert Cliffs, Nine Mile Point or Ginna, it could have a
- the facts and circumstances relating to the alleged substantial adverse impact on our financial results.
exposure.
Until the relevant facts for both types of claims are Nuclear Liability Insurance determined, we are unable to estimate what our, or BGE's, Pursuant to the Price-Anderson Act, we are required to insure liability might be. Although insurance and hold harmless against public liability claims resulting from nuclear incidents to agreements from contractors who employed the plaintiffs may the full limit of public liability. This limit of liability consists of cover a portion of any awards in the actions, the potential effect the maximum available commercial insurance of $300 million on our, or BGE's. financial results could be material. and mandatory participation in an industry-wide retrospective premium assessment program. The retrospective premium Storage of Spent Nuclear Fuel assessment is $100.6 million per reactor, increasing the total The Nuclear Waste Policy Act of 1982 (NWPA) required the amount of insurance for public liability to approximately federal government through the Department of Energy (DOE), $10.8 billion. Under the retrospective assessment program, we to develop a repository for, and disposal of, spent nuclear fuel can be assessed up to $503 million per incident at any and high-level radioactive waste. The NWPA and our contracts commercial reactor in the country, payable at no more than with the DOE required the DOE to begin taking possession of $50 million per incident per year. This assessment also applies in spent nuclear fuel generated by nuclear generating units no later excess of our worker radiation claims insurance and is subject to than January 31, 1998. The DOE has stated that it will not inflation and state premium taxes. Claims resulting from meet that obligation until 2010 at the earliest. This delay has non-certified acts of terrorism are limited to the commercial required that we undertake additional actions related to on-site insurance discussed above, regardless of the number of nuclear fuel storage at Calvert Cliffs and Nine Mile Point, including the plants affected. In addition, the U.S. Congress could impose installation of on-site dry fuel storage capacity at Calvert Cliffs. additional revenue-raising measures to pay claims.
In January 2004, we filed a complaint against the federal government in the United States Court of Federal Claims Worker Radiation Claims Insurance seeking to recover damages caused by the DOE's failure to meet \'Ve participate in the American Nuclear Insurers Master Worker its contractual obligation to begin disposing of spent nuclear fuel Program that provides coverage for worker tort claims filed for by January 31, 1998. The cases are currently stayed, pending radiation injuries. Effective January 1, 1998, this program was litigation in other related cases. modified to provide coverage to all workers whose nuclear-In connection with our purchase of Ginna, all of Rochester related employment began on or after the commencement date Gas & Electric Corporation's (RG&E) rights and obligations of reactor operations. Waiving the right to make additional related to recovery of damages from the DOE were assigned to claims under the old policy was a condition for coverage under us. However, we have an obligation to reimburse RG&E for up the new policy. We describe the old and new policies below-to the first $10 million in recovered damages. We and RG&E
- Nuclear worker claims reported on or after January 1, are currently requesting to allow us to replace RG&E as the 1998 are covered by a new insurance policy with a parry in interest in the complaint filed against the federal single industry aggregate limit of $300 million for government by RG&E. radiation injury claims against all those insured by this policy.
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- All nuclear worker claims reported prior to January 1, Non-Nuclear Property Insurance 1998 are still covered by the old policy. Insureds under Our conventional property insurance provides coverage of the old policies, with no current operations, are not $1.0 billion per occurrence for Certified acts of terrorism as required to purchase the new policy described on the defined under the Terrorism Risk Insurance Act of 2002.
previous page, and may still make claims against the old Certified acts of terrorism are determined by the Secretary of policies through 2007. If radiation injury claims under State and Attorney General of the United States and primarily these old policies exceed the policy reserves, all are based upon the occurrence of significant acts of international policyholders could be retroactively assessed, with our terrorism. Our conventional property insurance program also share being up to $6.3 million. provides coverage for non-certified acts of terrorism up to an The sellers of Nine Mile Point retain the liabilities for annual aggregate limit of $333.0 million. If a terrorist act occurs existing and potential claims that occurred prior to November 7, at any of our facilities, it could have a significant adverse impact 2001. In addition, the Long Island Power Authority, which on our financial results.
continues to own 18% of Unit 2 at Nine Mile Point, is obligated to assume its pro rata share of any liabilities for California Power Purchase Agreements retrospective premiums and other premiums assessments. RG&E, Our merchant energy business has $240.2 million invested in the seller of Ginna, retains the liabilities for existing and operating power projects of which our ownership percentage potential claims that occurred prior to June 10, 2004. If claims represents approximately 140 megawatts of electricity that are under these policies exceed the coverage limits, the provisions of sold to Pacific Gas & Electric (PGE) and to Southern California the Price-Anderson Act would apply. Edison (SCE) in California under power purchase agreements.
As a result of two proceedings initiated by certain Nuclear Property Insurance California utilities and others before the California Public Utility Our policies provide $500 million in primary coverage at Commission challenging prices under power purchase agreements Calvert Cliffs, Nine Mile Point, and Ginna. In addition, we for periods between June 2000 and March 2001, the potential maintain $2.25 billion in excess coverage at Calvert Cliffs and exists that certain California power generation projects in which Nine Mile Point and $1.77 billion of excess coverage at Ginna we have an ownership interest could be required to pay refunds.
for property damage, decontamination, and premature We believe the price for energy payments were appropriate and decommissioning liability. This coverage currently is purchased any refund would be unwarranted. Our current estimate of through an industry mutual insurance company. If accidents at potential exposure that could result from an adverse ruling in plants insured by the mutual insurance company cause a the proceeding is between $2.5 million and $5.0 million.
shortfall of funds, all policyholders could be assessed, with our However, we cannot determine the actual amount we could be share being up to $91.7 million. required to pay because litigation is ongoing and new events Losses resulting from non-certified acts of terrorism are could occur that may cause the actual amount, if any, to be covered as a common occurrence, meaning that if non-certified materially different from our estimate.
terrorist acts occur against one or more commercial nuclear power plants insured by our nuclear property insurance company within a 12-month period, they would be treated as one event and the owners of the plants would share one full limit of liability (currently $3.24 billion).
Accidental Nuckar Outage Insurance Our policies provide indemnification on a weekly basis for losses resulting from an accidental outage of a nuclear unit. Coverage begins after a I2-.week deductible period and continues at 100%
of the weekly indemnity limit for 52 weeks and then 80% of the weekly indemnity limit for the next 110 weeks. Our coverage is up to $490.0 million per unit at Calvert Cliffs and Ginna, $420.0 million for Unit I of Nine Mile Point, and
$401.8 million for Unit 2 of Nine Mile Point. This amount can be reduced by up to $98.0 million per unit at Calvert Cliffs and
$84.0 million for Nine Mile Point if an outage of more than one unit is caused by a single insured physical damage loss.
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13 Hedging Activities and Fair Value of Financial Instruments SFAS No. 133 Hedging Activities Commodity Prices We are exposed to market risk, including changes in interest Our merchant energy business uses a variety of derivative and rates and the impact of market fluctuations in the price and non-derivative instruments to manage the commodity price risk transportation costs of electricity, natural gas, and other of our competitive supply activities and our electric generation commodities. facilities, including power sales, fuel and energy purchases, gas purchased for resale, emission credits, weather risk, and the Interest Rates market risk of outages. In order to manage these risks, we may We use interest rate swaps to manage our interest rate exposures enter into fixed-price derivative or non-derivative contracts to associated with new debt issuances and to optimize the mix of hedge the variability in future cash flows from forecasted sales of fixed and floating-rate debt. The swaps used to manage our energy and purchases of fuel and energy. The objectives for exposure prior to the issuance of new debt are designated as entering into such hedges include:
cash-flow hedges under SFAS No. 133, Accountingfir Derivatve
- fixing the price for a portion of anticipated future Instruments and Hedging Activities, as amended, with the effective electricity sales at a level that provides an acceptable portion of gains and losses, net of associated deferred income tax return on our electric generation operations, effects, recorded in "Accumulated other comprehensive income"
- fixing the price of a portion of anticipated fuel in our Consolidated Statements of Common Shareholders' purchases for the operation of our power plants, Equity and Comprehensive Income and Consolidated Statements
- fixing the price for a portion of anticipated energy of Capitalization, in anticipation of planned financing purchases to supply our load-serving customers, and transactions. We reclassify gains and losses on the hedges from
- fixing the price for a portion of anticipated sales of "Accumulated other comprehensive income" into "Interest natural gas to customers.
expense" in our Consolidated Statements of Income during the. The portion of forecasted transactions hedged may vary periods in which the interest payments being hedged occur. based upon management's assessment of market, weather, The swaps used to optimize the mix of fixed and floating- operational, and other factors.
rate debt are designated as fair value hedges under SFAS At December 31, 2004, our merchant energy business had No. 133. We record any gains or losses on swaps that qualify for designated certain fixed-price forward contracts as cash-flow fair value hedge accounting treatment, as well as changes in the hedges of forecasted sales of energy and forecasted purchases of fair value of the debt being hedged, in "Interest expense," and fuel and energy for the years 2005 through 2011 under SFAS No. 133. Our merchant energy business had net unrealized we record any changes in fair value of the swaps and the debt in "Risk management assets and liabilities" and "Long-term debt" pre-tax losses on these cash-flow hedges recorded in "Accumulated other comprehensive income" of $103.8 million at in our Consolidated Balance Sheets. In addition, we record the December 31, 2004 and net unrealized pre-tax gains of difference between interest on hedged fixed-rate debt and
$16.1 million at December 31, 2003. We expect to reclassify floating-rate swaps in "Interest expense" in the periods that the
$154.5 million of net pre-tax gains on cash-flow hedges from swaps settle.
"Accumulated other comprehensive income" into earnings during At December 31, 2004 and 2003, we had net unrealized the next twelve months based on the market prices at pre-tax gains on interest rate cash-flow hedges recorded in December 31, 2004. However, the actual amount reclassified "Accumulated other comprehensive income" of $18.3 million into earnings could vary from the amounts recorded at and $21.2 million, respectively. We expect to reclassify December 31, 2004, due to future changes in market prices.
$2.9 million of pre-tax net gains on these cash-flow hedges from Additionally, for cash-flow hedges settled by physical delivery of "Accumulated other comprehensive income" into "Interest the underlying commodity. Reclassification of net gains on expense" during the next twelve months. We had no hedge hedging instruments from OCI to net income" represents the ineffectiveness on these swaps. fair value of those derivatives, which is realized through gross During 2004, to optimize the mix of fixed and floating-rate settlement at the contract price. In 2004, we recognized debt, we entered into interest rate swaps qualifying as fair value $3.0 million of pre-tax losses in earnings related to cash-flow hedges relating to $450 million of our fixed-rate debt maturing hedge ineffectiveness.
in 2012 and 2015, and converted this notional amount of debt Our merchant energy business also enters into natural gas to floating-rate. At December 31, 2004, the $13.3 million storage contracts that qualify for fair value hedge accounting increase in the fair value of these hedges, for which there was no treatment under SFAS No. 133. During 2004, we had hedge ineffectiveness, was recorded as an increase in our "Risk unrealized pre-tax gains of $2.2 million and unrealized pre-tax management assets" and "Long-term debt." losses of $0.4 million due to hedge ineffectiveness, and the resulting pre-tax net gain of $1.8 million was recognized into earnings during 2004. We record changes in fair value of these hedges as a component of "Fuel and purchased energy expenses" in our Consolidated Statements of Income.
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Regulated Gas Business
- investments and other assets: the fair value is based on BGE uses basis swaps in the winter months (November quoted market prices where available, and through March) to hedge its price risk associated with natural
- long-term debt: the fair value is based on quoted gas purchases under its market-based rates incentive mechanism market prices where available or by discounting and under its off-system gas sales program. BGE also uses remaining cash flows at current market rates.
fixed-to-floating and floating-to-fixed swaps to hedge its price We show the carrying amounts and fair values of financial risk associated with its off-system gas sales. The fixed portion instruments included in our Consolidated Balance Sheets in the represents a specific dollar amount that BGE will pay or following table.
receive, and the floating portion represents a fluctuating amount based on a published index that BGE will receive or At December 31, 2004 2003 pay. BGE's regulated gas business internal guidelines do not Carrying Fair Carrying Fair Amount Value Amount Value permit the use of swap agreements for any purpose other than to hedge price risk. (In millions)
Investments and other assets-Fair Value of Financial Instruments Constellation The fair value of a financial instrument represents the amount Energy $1,190.0 $1,191.2 S 898.7 S 902.2 at which the instrument could be exchanged in a current Faxed-rate long-transaction between willing parties, other than in a forced sale term debt:
or liquidation. Significant differences can occur between the Constellation Energy 4,468.5 4,979.7 5,069.4 5,723.5 fair value and carrying amount of financial instruments that are BGE 1,404.3 1,468.2 1,549.3 1,787.4 recorded at historical amounts. We use the following methods Variable-rate and assumptions for estimating fair value disciosures for long-term financial instruments: debt:
- cash and cash equivalents, net accounts receivable, Constellation Energy 835.6 835.6 323.2 323.2 other current assets, certain current liabilities, BGE 99.3 99.3 104.1 104.1 short-term borrowings, current portion of long-term debt, and certain deferred credits and other liabilities: Certainprior-year amounts have been reclassified to conform with because of their short-term nature, the amounts the currentyear!s presentation.
reported in our Consolidated Balance Sheets approximate fair value, 1 4 Stock-Based Compensation Under our long-term incentive plans, we granted stock options, In February 2002, our Compensation Committee of the performance and service-based restricted stock, performance- Board of Directors granted options, contingent on shareholder based units, and equity to officers, key employees, and members approval of our long-term incentive plan, with an exercise price of the Board of Directors. Under the plans, we can grant up to equal to the fair market value of our stock on the date of grant a total of 18,000,000 shares. At December 31, 2004, we had of $27.93. Our shareholders approved the plan at the annual stock options, restricted stock, and stock unit grants outstanding meeting in May 2002 when the stock price had increased to as discussed below. BGE officers and key employees participate $31.21. The difference between the exercise price and the fair in our stock-based compensation plans. The expense recognized market value in May when the shareholder approval contingency by BGE in 2004, 2003, and 2002 was not material to BGE's was satisfied was $6.3 million and is being amortized to financial results. compensation expense over a period up to five years. We recorded compensation expense of $1.0 million in 2004, Non-Qualified Stock Options $1.8 million in 2003, and $3.0 million in 2002 related to this Options are granted with an exercise price not less than the grant.
market value of the common stock at the date of grant, become All other stock option grants have an exercise price equal to vested over a period up to five years, and expire ten years from or greater than market value on the date of grant and were not the date of grant. In accordance with APB No. 25, no subject to any future contingencies, therefore no compensation compensation expense is recognized for these awards. expense has been recognized. We reverse any expense associated with stock options that are canceled or forfeited prior to the vesting of the grants. Summarized information for our stock option grants is as follows:
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2004 2003 2002 Weighted- Weighted- Weighted-Average Average Aver e Shares Exercise Price Shares Exercse lrice Shares Exercise P'rice (In shousands. except for exercise prices)
Outstanding, beginning of year 7,117 $29.53 6,081 $29.65 2.646 $30.73 Granted with exercise prices:
At fair market value 1,640 39.60 1,485 29.24 1,708 30.62 Less than fair market value on the date contingency was satisfied (1) - - - - 1,935 27.93 Greater than fair market value - - 9 28.53 103 31.21 Total granted 1,640 39.60 1,494 29.24 3,746 29.25 Exercised (834) 28.49 (267) 27.92 - -
Canceled/Expired (558) 33.09 (191) 33.28 (311) 34.01 Outstanding, end of year 7,365 $31.62 7,117 $29.53 6,081 $29.65 Exercisable, end of year 3,844 $29.99 3,169 $29.89 1,413 $30.78 Weighted-average fair value per share of options granted with exercise prices:
At fair market value $ 7.22 $ 6.80 $ 7.79 Less than fair market value on the date contingency was satisfied (1) - - 9.15 Greater than fair market value - 5.56 5.89 (1) Shares were granted in February 2002 with an exercise price equal to the fair market value of the stock on the grant date, and the grant was subject to shareholder approval of our long-term incentive plan. At the date of shareholder approval, the fair market value of the stock was higher than the grant date fair market value. Therefore, the difference is being amortized to compensation expense.
The following table summarizes information about stock We recorded compensation expense related to our options outstanding at December 31, 2004 (stock options in restricted stock awards of $17.0 million in 2004, $16.4 million thousands): in 2003, and $6.6 million in 2002. Summarized share information for our restricted stock awards is as follows:
Weighted.
Stock Average Stock 2004 2003 2002 Range of Options Remaining Options (In thousandi)
Exercise Prices Outstanding Contractual Life Exercisable Outstanding, beginning of year 752 314 435
$21.47 - $25.00 33 7.8 years 18 Granted 1,002 555 344
$25.00 - $30.00 3,678 7.5 years 2,053 Released to participants (467) (109) (170)
$30.00 - $35.00 2,167 6.3 years 1,768 Canceled (64) (8) (295)
$35.00 - $40.72 1,487 9.2 years 5 Outstanding. end of year 1,223 752 314 Restricted Stock Awards Weighted-average fair value In addition, we issue common stock based on meeting certain restricted stock granted $38.83 $30.53 $27.23 performance and/or service goals. This stock vests to participants at various times ranging from one to five years if Performance-Based Units the performance and/or service goals are met. In accordance During 2004, we granted 11.6 million of performance-based with APB No. 25, we recognize compensation expense for our units to officers and key employees of which 1.1 million units performance-based awards using the variable accounting were forfeited prior to year end. Each unit is equivalent to $1 method, whereby we amortize the value of the market price of in value and vests at the end of a three-year service and the underlying stock on the date of grant (adjusted for performance period. The level of payout is based on the subsequent changes in fair market value through the achievement of certain performance goals at the end of the performance measurement date) to compensation expense over three-year period and at least 50% of any payouts will be the service period. We account for our service-based awards settled in cash, and the other 50% may be settled in either using the fixed accounting method, whereby we amortize the stock or cash at our discretion. We recorded compensation value of the market price of the underlying stock on the date expense of $2.9 million in 2004 related to these performance-of grant to compensation expense over the service period. We based units.
reverse any expense associated with restricted stock that is canceled or forfeited during the performance or service period. Equity-Based Grants We recorded compensation expense of $0.5 million in 2004,
$0.4 million in 2003, and $0.5 million in 2002 related to equity-based grants to members of the Board of Directors.
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Pro-forma Information WXe disdose the pro-forma effect on net income and Disclosure of pro-forma information regarding net income and earnings per share in accordance with SFAS No. 148, earnings per share is required under SFAS No. 123, which uses Accountingfor Stock-Based Compensation-Transition and the fair value method. The fair value of our stock-based awards Disclosure, in Note 1. Also, as discussed in more derail in were estimated as of the date of grant using the Black-Scholes Note 1, the FASB issued SFAS No. 123R in December 2004, option pricing model based on the following weighted-average which changed the accounting for stock-based compensation, assumptions: requiring companies to expense stock options and other equity awards based on their grant-date fair values.
2004 2003 2002 Risk-free interest rate 3.15% 2.92% 4.45%
Expected life (in years) 5.0 5.0 5.0 Expected market price volatility factor 23.7% 32.0% 31.9%
Expected dividend yield 3.0% 3.3% 3.3%
I 5 Acquisitions Acquisition of Ginna The intangible assets acquired consist of the following:
On June 10, 2004, we completed our purchase of the Ginna nuclear facility, which is located in Ontario, New York from Weighted-RG&E. Ginna consists of a 495 megawatt reactor that entered Average service in 1970 and is licensed to operate until 2029. Description Amount Useful Life We purchased 100 percent of Ginna for $457.3 million (In millions) (In yean) induding direct costs associated with the acquisition, of which Operating procedures and manuals S26.1 25
$430.0 million was paid in cash at dosing and the remaining Permits and licenses 8.5 25
$27.3 million was paid during the second half of 2004. RG&E Software 4.2 5 also transferred to us $200.8 million in decommissioning funds. Total intangible assets $38.8 We will sell 90 percent of Ginna's output back to RG&E at an average price of nearly $44 per megawatt-hour until Acquisition of Blackhawk Energy Services and Kaztex June 2014 under a unit contingent power purchase agreement (if Energy Management the output is not available because the plant is not operating, On October 22, 2003, we completed our purchase of Blackhawk there is no requirement to provide output from other sources). Energy Services (Blackhawk) and Kaztex Energy Management The acquisition of Ginna was immediately accretive to earnings. (Kaztex). We include Blackhawk and Kaztex, part of our retail We accounted for this transaction as an asset acquisition gas operation, in our merchant energy business segment and and induded Ginna in our merchant energy business segment. have included their results in our consolidated financial Our purchase price allocation for the net assets acquired is as statements since the date of acquisition. Blackhawk and Kaztex follows: are providers of natural gas and electricity services. At the time of the acquisition, Blackhawk and Kaztex served approximately At June 10, 2004 1,100 customers representing approximately 70 billion cubic feet (In millions) of natural gas and 0.9 million megawatt hours of electricity Current Assets $ 27.9 throughout Illinois and Wisconsin. We acquired 100%
Nudear Decommissioning Trust Fund 200.8 ownership of both companies for $26.9 million cash. We Nudear Fuel 14.5 Net Property, Plant and Equipment 382.8 acquired cash of $1.2 million as part of the purchase.
Intangible Assets (details below) 38.8 Other Assets 124.0 Total Assets Acquired 788.8 Current Liabilities (20.8)
Asset Retirement Obligations (177.3)
Deferred Credits and Other liabilities (133.4)
Net Assets Acquired $457.3 112
Our purchase price allocation for the net assets acquired is We believe that the pro-forma impact on Income before as follows: cumulative effect of change in accounting principle," "Net income," and 'Earnings per common share" would not have At October 22. 2003 been material had the acquisition of Blackhawk and Kaztex (In millions) occurred on the first day of each of the years presented.
Cash $ 1.2 Other Current Assets 41.0 Acquisition of the High Desert Power Project Total Current Assets 42.2 In April 2003, our High Desert Power Project in Victorville, Net Property. Plant and Equipment 0.1 California, an 830 megawatt (MW) gas-fired combined cycle Goodwill 25.9 facility, commenced operations. The project has a long-term Other Assets 0.9 power sales agreement with the California Department of Water Total Assets Acquired 69.1 Resources (CDWR). The contract is a "tolling" structure, under Current liabilities (40.8) which the CDWR pays a fixed amount of $12.1 million per Deferred Credits and Other liabilities (1.4) month and provides CDWR the right, but not the obligation, to Net Assets Acquired $26.9 purchase power from the project at a price linked to the variable cost of production. During the term of the contract, which runs We recorded the existing contracts at fair value as part of for seven years and nine months from the April 2003 the purchase price allocation. The fair value of the contracts was commercial operation date of the plant, the project will provide a net liability of $0.4 million. We recorded the fair value of these contracts as follows: energy exclusively to the CDWR.
Prior to June 2003, we accounted for this project as an Net fair value of acquired contracts operating lease. In June 2003, we elected to refinance the lease (In millions) to extend the tenor of the financing at attractive interest rates.
Current Assets $ 3.2 Accordingly, we exercised our option under the lease associated Noncurrent Assets 0.1 with the High Desert Power Project, paid off the lease, and acquired the assets from the lessor. Beginning June 30, 2003, the Total Assets 3.3 assets and liabilities associated with the High Desert Power Current liabilities (2.3) Project were included in our Consolidated Balance Sheets. We Noncurrent Liabilities (1.4) accounted for this transaction as an asset acquisition and Total Liabilities (3.7) included the High Desert Power Project in our merchant energy Net fair value of acquired contracts $(0.4) segment.
Our purchase price allocation for the net assets acquired is Acquired contracts include both executory contracts and as follows:
risk management liabilities associated with certain hedges. We are amortizing the acquired executory contracts over a period At June 27 2003 extending through 2008. The weighted-average amortization (un millions) period is approximately 20 months and represents the expected Cash $ 4.3 contract duration. The risk management liabilities are accounted Other Current Assets 1.6 for as described in Note 1. Other Noncurrent Assets 1.7 On an unaudited pro-forma basis, had the acquisition of Net Property Plant and Equipment 528.3 Blackhawk and Kaztex occurred on the first day of each of the Total Assets Acquired 535.9 periods presented below, our nonregulated revenues and total Accounts Payable (17.5) revenues would have been as follows:
Net Assets Acquired $518.4 Year Ended December 31. 2003 2002 (In millions)
Nonregulated revenues As reported 7,053.6 2,182.5 Pro-forma 7,408.5 2,410.0 Total revenues As reported 9,687.8 4,718.6 Pro-forma 10,042.7 4,946.1 113
Acquisition of Alliance Acquisition of NewEnergy On December 31, 2002, we purchased Alliance Energy Services, On September 9, 2002, we purchased AES NewEnergy, Inc.
LLC and Fellon-McCord Associates, Inc. (collectively, Alliance) from AES Corporation. Subsequent to the acquisition, we from Allegheny Energy, Inc. We include Alliance (renamed renamed AES NewEnergy, Inc. as Constellation NewEnergy, Inc.
Constellation NewEnergy Gas in 2004), our retail gas operation, (NewEnergy). We include NewEnergy, our retail electric in our merchant energy business segment and have included operation, in our merchant energy business segment and have their results in our consolidated financial statements since the included their results in our consolidated financial statements date of acquisition. These businesses provide gas supply and since the date of acquisition. NewEnergy is a leading national transportation services and energy consulting services to provider of electricity, natural gas, and energy services, serving commercial and industrial customers primarily in the Midwest approximately 4,300 megawatts of load at acquisition associated region, but also in other competitive energy markets including with commercial and industrial customers in competitive energy the Northeast, Mid-Atlantic, Texas and California regions. markets including the Northeast, Mid-Atlantic, Midwest, Texas On an unaudited pro-forma basis, had the acquisition of and California.
our retail gas operation occurred on the first day of 2002, our On an unaudited pro-forma basis, had the acquisition of nonregulated revenues and total revenues would have been as NewEnergy occurred on the first day of 2002, our nonregulated follows: revenues and total revenues would have been as follows:
Year Ended December 31, Year Ended December 31, (In milions) (In milions)
Nonregulated revenues Nonregulated revenues As reported $2,182.5 As reported $2,182.5 Pro-forma 2,722.2 Pro-forma 3,323.3 Total revenues Total revenues As reported $4,718.6 As reported $4,718.6 Pro-forma 5,258.3 Pro-forma 5,859.4 We believe that the pro-forma impact on 'Income before We believe that the pro-forma impact on Income before cumulative effect of change in accounting principle," "Net cumulative effect of change in accounting principle," 'Net income," and 'Earnings per common share" would not have income," and "Earnings per common share" would not have been material had the acquisition of our retail gas operation been material had the acquisition of NewEnergy occurred on the occurred on the first day of each of the years presented. first day of each of the years presented.
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16 Related Party Transactions-BGE Income Statement Balance Sheet BGE provides standard offer service to those customers that do BGE participates in a cash pool under a Master Demand Note nor choose an alternate supplier. Our wholesale marketing and agreement with Constellation Energy. Under this arrangement, risk management operation provided BGE with the energy and participating subsidiaries may invest in or borrow from the pool capacity required to meet its commercial and industrial standard at market interest rates. Constellation Energy administers the offer service obligations through June 30, 2004 and provides the pool and invests excess cash in short-term investments or issues energy and capacity required to meet its residential standard commercial paper to manage consolidated cash requirements.
offer service obligations through June 30, 2006. Effective July 1, Under this arrangement, BGE had invested $127.9 million at 2004, BGE executed one and two-year contracts for commercial December 31, 2004 and $230.2 million at December 31, 2003.
and industrial electric power supply totaling approximately 2,300 Amounts related to corporate functions performed at the megawatts. Our wholesale marketing and risk management Constellation Energy holding company, BGE's purchases to meet operation is supplying a significant portion of this electric power its standard offer service obligation, BGE's charges to supply. Constellation Energy and its nonregulated affiliates for certain The cost of BGE's purchased energy from nonregulated services it provides them, and the participation of BGE's affiliates of Constellation Energy to meet its standard offer employees in the Constellation Energy pension plan result in service obligation was as follows: intercompany balances on BGE's Consolidated Balance Sheets.
We believe our allocation methods are reasonable and Year Ended December 31, 2004 2003 2002 approximate the costs that would be charged to unaffiliated (In millioni) entities.
Electricity purchwsed for resale expenses $ 948.9 S1,023.4 SI.080.5 In addition, Constellation Energy charges BGE for the costs of 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. We believe this method of allocation is reasonable and approximates the cost BGE would have incurred as an unaffiliated entity. These costs were:
- $99.8 million for the year ended December 31, 2004,
- $84.0 million for the year ended December 31, 2003, and
- $37.6 million for the year ended December 31, 2002.
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1 7 Quarterly Financial Data (Unaudited)
Our quarterly financial information has not been audited but, in management's opinion, includes all adjustments necessary for a fair presentation. Our business is seasonal in nature with the peak sales periods generally occurring during the summer and winter months. Accordingly, comparisons among quarters of a year may not represent overall trends and changes in operations.
2004 Quarterly Dara-Constelladion Energy 2004 Quarterly Dara-BGE Income Before Cumulative Earnings Per Earnings Per Effects of Earnings Share Irom Share of Eanings Income Changes in Applicabl Continuing Common Income APpIcale from Accounting to Common Operaions- Stock- from to Common Revenues Operations Principles Stock Diluted Diluted Revenues Operations Stock (In miionr, except per stare emounts) (In millioni)
Quarter Ended Quarter Ended March31 S 3,036.6 S 235.7 $112.5 $ 66.2 $0.66 S 0.39 March 31 $ 803.9 $149.8 $ 72.7 June 30 2,793.0 195.9 130.9 128.2 0.77 0.76 June 30 589.8 65.6 21.9 September 30 3,434.5 396.5 210.6 210A 1.19 1.19 September 30 657.3 77.1 28.1 December 31 3,285.6 249.1 134.8 134.9 0.76 0.76 December 31 673.7 78.9 30A Year Ended Year Ended December 31 $12,549.7 $1,077.2 $588.8 $ 539.7 $3.40 $ 3.12 December 31 $2,724.7 $371A $153.1 The sum of the quarterly earningsper sharr amounts may not equalthe totalfor the year due to the effects of rounding and dilution as a result of issuing common shares during the year.
First quarter results include:
Constellation Energy
- a $46.3 million loss after-tax for the discontinued operations of our Hawaiian geothermal facility, and
- gain on the sale of investments and other assets of $1.0 million after-tax.
Second quarter results include:
Constellation Energy
- recognition of 2003 synfuel tax credits of $35.9 million after-tax,
- a $2.7 million loss after-tax for the discontinued operations of our Hawaiian geothermal facility,
- gain on the sale of investments of $2.7 million after-tax, and
- an other than temporary decline in value of our investments of $1.6 million after-tax.
Third quarter results include:
Constellation Energy
- net loss on sale of investment and other assets of $4.6 million after-tax,
- an other than temporary decline in value of our investments of $0.6 million after-tax, and
- a $0.2 million loss after-tax for the discontinued operations of our Hawaiian geothermal facility.
Fourth quarter results include:
Constellation Energy
- workforce reduction costs totaling $5.9 million after-tax,
- net gain on sale of investments of $0.3 million after-tax, and
- a $0.1 million gain after-tax for the discontinued operations of our Hawaiian geothermal facility.
We discuss our special items in Note 2.
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2003 Quarterly Data-Consteliation Energy 2003 Quarterly Data-BGE Earnings PC] rShare Asn ;uming Diilution Income 8 aefore Before Cur nulative (Loss)
Cumulative (Loss) Eflects or Earnings Effects of Earnings Cluinges in Per Share of Earnings Income Changes in Applicablet Ac ounting Common Income from Accounting to Common Prirriciples- Stock- from toptmc"oen Revenues Operations Principles" Stock Diluted Diluted Revenues Operations Stock (In milion,. exceptPer shore amountrs) (In milionjs)
Quarter Ended Quarter Ended March 31 S 2326.1 S 175.6 S 67.0 $ (131.4) $ 0.40 S (0.80) March 31 S 789.8 $164.6 S 78.5 June 30 2.266.6 229.1 96.8 96.8 0.58 0.58 June 30 577.0 69.2 2 MF September 30 2,600.6 389.2 192.9 192.9 1.15 1.15 September 30 663.3 62.8 20.6 December31 2,494.5 272.4 119.0 119.0 0.71 0.71 December31 617.5 88.4 29.2 YearEnded YearEnded December31 S 9,687.8 $ 1,066.3 $ 475.7 S 277.3 S2.85 $ 1.66 December 31 $2,647.6 $385.0 $150.CI The sum ofthe quarterly earningsper share amounts may not equal the total/fr the year due to the effects ofrounding and dilution as a result ofissuing common shares during the year.
Certainprior-periodamounts have been reclassified to conform with the currentyears presentation.
First quarter results include:
Constellation Energy and BCE
- workforce reduction costs totaling $0.4 million after-tax, of which BGE recorded $0.1 million.
Constellation Energy
- a $266.1 million loss after-tax for the cumulative efect of adopting EITF 02-3,
- a $67.7 million gain after-tax for the cumulative effect of adopting SFAS 143, and
- gain on the sale of investments and other assets of $8.3 million after-tax.
Second quarter results include:
Constelation Energy and BGE
- workforce reduction costs totaling $0.4 million after-tax, of which BGE recorded $0.1 million.
Constelation Energy
- gain on the sale of investments of $0.3 million after-tax.
Third quarter results include:
Constellation Energy and BGE
- workforce reduction costs totaling $0.5 million after-tax, of which BGE recorded $0.2 million.
Constellation Energy
- net gain on sale of investment and other assets of $1.4 million after-tax.
Fourth quarter results include:
Constellation Energy
- net gain on sale of investments of $6.4 million after-tax and,
- an other than temporary decline in the value of our investment in an airplane of $0.4 million after-tax.
We discuss our special items in Note 2.
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Item 9. Changes In and Disagreements with Accountants on Accounting and Financial Disclosure None.
Item OA. Controls and Procedures Evaluation of Disclosure Controls and Procedures The principal executive officers and principal financial officer of both Constellation Energy and BGE have evaluated the effectiveness of the disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the 'Exchange Act")) as of December 31, 2004 (the
'Evaluation Date"). Based on such evaluation, such officers have concluded that, as of the Evaluation Date, Constellation Energys and BGE's disclosure controls and procedures are effective, in that they provide reasonable assurance that such officers are alerted on a timely basis to material information relating to Constellation Energy and BGE that is required to be included in Constellation Energys and BGE's periodic filings under the Exchange Act.
Internal Control Over FinancialReporting Constellation Energy maintains a system of internal control over financial reporting as defined in Exchange Act Rule 13a-15(f). Constellation Energy's Management Report on Internal Control Over Financial Reporting is included in Item 8. Financial Statements and Supplementary Data included in this report. As BGE is not an accelerated filer as defined in Exchange Act Rule 12b-2, it is not required to provide a report of management on the effectiveness of its internal control over financial reporting as of December 31, 2004, but will be required to do so as of December 31, 2006.
Changes In Internal Control During the quarter ended December 31, 2004, there has been no change in either Constellation Energy's or BGE's internal control over financial reporting (as such term is defined in Rules 13a -15(f) and 15d-15(f) under the Exchange Act) that has materially affected, or is reasonably likely to materially affect, either Constellation Energy's or BGE's internal control over financial reporting.
Subsequent to this reporting period, during January 2005, Constellation Energy implemented a new enterprise reporting platform, which included a general ledger and various sub-ledgers, for certain of its operating subsidiaries.
Following this implementation, substantially all of Constellation Energy's operating subsidiaries are using the new system. The implementation affected systems that include certain internal controls, and accordingly, the implementation has required revisions to our internal control over financial reporting. We reviewed the system as it was implemented as well as the controls affected by the implementation of the system and made appropriate changes to affected internal controls.
Item 9B. Other Information None.
PART III The information required by this item with respect BGE meets the conditions set forth in General to executive officers of Constellation Energy Group, Instruction I(l)(a)and (b) of Form 10-K for a reduced pursuant to instruction 3 of paragraph (b) of Item 401 disclosure format. Accordingly, all items in this section of Regulation S-K, is set forth following Item 4 of related to BGE are not presented. Part I of this Form 10-K under Erecutive Officers of the Registrant.
Item 10. Directors and Executive Officers of the Registrant Item 11. Executive Compensation The information 'required by this item with respect to The information required by this item is set forth under directors is set forth under Election of Constellation Directors Compensation, Executive Compensation, Energy Directors in the Proxy Statement and is Common Stock Performance Graph and Report of incorporated herein by reference. Compensation Committee on Executive Compensation in the Proxy Statement and is incorporated herein by reference.
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Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters Equity Compensation Plan Information The following table reflects our equity compensation plan information as of December 31, 2004:
(a) (b) (c)
Number of securities Number of securities remaining to be issued upon Weighted-average available for future issuance exercise of exercise price of under equity compensation outstanding options, outstanding options, plans (excluding securities Plan Category warrants, and rights warrants, and rights reflected in item (a))
(In thousands) (In thousands)
Equity compensation plans approved by security holders 5,346 $32.18 3,814 Equity compensation plans not approved by security holders 2,019 $30.14 2,071 Total 7,365 $31.62 5,885 The plans that do not require security holder approval are the Constellation Energy Group, Inc. 2002 Senior Management Long-Term Incentive Plan (Designated as Exhibit No. 10(v)) and the Constellation Energy Group, Inc.
Management Long-Term Incentive Plan (Designated as Exhibit No. 10(w)). A brief description of the material features of each of these plans is set forth below.
2002 Senior Management Long-Term Incentive Plan The 2002 Senior Management Long-Term Incentive Plan was effective May 24, 2002. Grants under the plan may be made to employees who are officers of Constellation Energy or hold senior management level or key employee positions with Constellation Energy or its subsidiaries. Under the plan, the Board of Constellation Energy has authorized the issuance of up to 5,000,000 shares of Constellation Energy common stock in connection with the grant of stock options, performance and service-based restricted stock and restricted stock units, performance units, stock appreciation rights, dividend equivalents and other equity awards. Any shares covered by an award that is forfeited or canceled, expires or is settled in cash, including the settlement of tax withholding obligations using shares, will become available for issuance under the plan. Shares delivered under the plan may be authorized and unissued shares, shares held in treasury or shares purchased on the open market in accordance with the applicable securities laws. Restricted stock, restricted stock unit-and performance unit award payouts will be accelerated and stock options and stock appreciation rights gains will be paid in cash in the event of a change in control, as defined in the plan. The plan is administered by Constellation Energy's Chief Executive Officer.
Management Long-Term Incentive Plan The Management Long-Term Incentive Plan was effective February 1, 1998. Grants under the plan may be made to employees of Constellation Energy who hold a management level position and other employees of Constellation Energy and its subsidiaries as may be designated by Constellation Energy's Chief Executive Officer. Under the plan, the Board of Constellation Energy has authorized the issuance of up to 3,000,000 shares of Constellation Energy common stock in connection with the grant of stock options, performance and service-based restricted stock and restricted stock units, performance units, stock appreciation rights and dividend equivalents. The number of shares available for issuance under the plan includes shares subject to awards that have lapsed or terminated. Shares delivered under the plan may be authorized and unissued shares, shares held in treasury or shares purchased on the open market in accordance with applicable securities laws. Restricted stock, restricted stock unit and performance units award payouts will be accelerated and stock options and stock appreciation rights will become fully exercisable in the event of a change in control, as defined by the plan. The plan is administered by Constellation Energy's Chief Executive Officer.
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Item 13. Certain Relationships and Related Transactions The additional information required by this item is set forth under Certain Relationhips and Transactions in the Proxy Statement and is incorporated herein by reference.
Item 14. Principal Accountant Fees and Services The information required by this item is set forth under ProposalNo. 2-Ratification of Appointment of PricewaterhouseCoopersLLP as Independent Registered Public Accounting Firm for 2005 in the Proxy Statement and is incorporated herein by reference.
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PART IV Item 15. Exhibits and Financial Statement Schedules (a) The following documents are filed as a part of this Report:
- 1. Financial Statements:
Reports of Independent Registered Public Accounting Firm dated March 10, 2005 of PricewaterhouseCoopers LLP Consolidated Statements of Income-Constellation Energy Group for three years ended December 31, 2004 Consolidated Balance Sheets-Constellation Energy Group at December 31, 2004 and December 31, 2003 Consolidated Statements of Cash Flows-Constellation Energy Group for three years ended December 31, 2004 Consolidated Statements of Common Shareholders' Equity and Comprehensive Income-Constellation Energy Group for three years ended December 31, 2004 Consolidated Statements of Capitalization-Constellation Energy Group at December 31, 2004 and December 31, 2003 Consolidated Statements of Income-Baltimore Gas and Electric Company for three years ended December 31, 2004 Consolidated Statements of Comprehensive Income-Baltimore Gas and Electric Company for three years ended December 31, 2004 Consolidated Balance Sheets-Baltimore Gas and Electric Company at December 31, 2004 and December 31, 2003 Consolidated Statements of Cash Flows-Baltimore Gas and Electric Company for three years ended December 31, 2004 Notes to Consolidated Financial Statements
- 2. Financial Statement Schedules:
Schedule II-Valuation and Qualifying Accounts Schedules other than Schedule 11 are omitted as not applicable or not required.
- 3. Exhibits Required by Item 601 of Regulation S-K Exhibit Number
- 2 -Agreement and Plan of Share Exchange between Baltimore Gas and Electric Company and Constellation Energy Group, Inc. dated as of February 19, 1999. (Designated as Exhibit No. 2 to the Registration Statement on Form S4 dated March 3, 1999, File No. 33-64799.)
'2(a) - Agreement and Plan of Reorganization and Corporate Separation (Nuclear). (Designated as Exhibit No. 2(a) to the Current Report on Form 8-K dated July 7, 2000, File Nos. 1-12869 and 1-1910.)
- 2(b) - Agreement and Plan of Reorganization and Corporate Separation (Fossil). (Designated as Exhibit No. 2(b) to the Current Report on Form 8-K dated July 7, 2000, File Nos. 1-12869 and 1-1910.)
'3(a) - Articles of Amendment and Restatement of the Charter of Constellation Energy Group, Inc. as of April 30, 1999. (Designated as Exhibit No. 99.2 to the Current Report on Form 8-K dated April 30, 1999, File No. 1-1910.)
'3(b) - Articles Supplementary to the Charter of Constellation Energy Group, Inc., as of July 19, 1999.
(Designated as Exhibit No. 3(a) to the Quarterly Report on Form I0-Q for the quarter ended June 30, 1999, File Nos. 1-12869 and 1-1910.)
'3(c) - Certificate of Correction to the Charter of Constellation Energy Group, Inc. as of September 13, 1999.
(Designated as Exhibit No. 3(c) to the Annual Report on Form 10-K for the year ended December 31, 1999, File Nos. 1-12869 and 1-1910.)
- 3(d) - Charter of BGE, restated as of August 16, 1996. (Designated as Exhibit No. 3 to the Quarterly Report on Form I0-Q for the quarter ended September 30, 1996, File No. 1-1910.)
'3(e) - Articles Supplementary to the Charter of Constellation Energy Group, Inc. as of November 20, 2001.
(Designated as Exhibit No. 3(e) to the Annual Report on Form 10-K for the year ended December 31, 2001, File Nos. 1-12869 and 1-1910.)
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'3(f) - Bylaws of Constellation Energy Group, Inc., as amended to February 27, 2004. (Designated as Exhibit 3(a) to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2004, File Nos.
1-12869 and 1-1910.)
- 3(g) - Bylaws of BGE, as amended to October 16, 1998. (Designated as Exhibit No. 3 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 1998, File No. 1-1910.)
- 4(a) - Indenture between Constellation Energy Group, Inc. and the Bank of New York, Trustee dated as of March 24, 1999. (Designated as Exhibit No. 4(a) to the Registration Statement on Form S-3 dated March 29, 1999, File No. 333-75217.)
'4(b) - First Supplemental Indenture between Constellation Energy Group, Inc. and the Bank of New York, Trustee dated as of January 24, 2003. (Designated as Exhibit No. 4(b) to the Registration Statement on Form S-3 dated January 24, 2003, File No. 333-102723.)
- 4(c) - Supplemental Indenture between BGE and Bankers Trust Company, as Trustee, dated as of June 20, 1995, supplementing, amending and restating Deed of Trust dated February 1, 1919. (Designated as Exhibit No. 4 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 1995, File No. 1-1910); and the following Supplemental Indentures between BGE and Bankers Trust Company, Trustee:
Exhibit Dated File No. Designated In Number
- January 15, 1992 3345259 (Form S-3 Registration) 4(a)(ii)
- February 15, 1993 1-1910 (Form 10-K Annual Report for 1992) 4(a)(i)
- March 1, 1993 1-1910 (Form 10-K Annual Report for 1992) 4(a)(ii)
- March 15, 1993 1-1910 (Form 10-K Annual Report for 1992) 4(a)(iii)
'April 15, 1993 1-1910 (Form 10-Q dated May 13, 1993) 4
- July 1, 1993 1-1910 (Form 10-Q dated August 13, 1993) 4(a)
October 15, 1993 1-1910 (Form 10-Q dated November 12, 1993) 4
- June 15, 1996 1-1910 (Form 10-Q dated August 13, 1996) 4
- 4(d) -Indenture dated July 1, 1985, between BGE and The Bank of New York (Successor to Mercantile-Safe Deposit and Trust Company), Trustee. (Designated as Exhibit 4(a) to the Registration Statement on Form S-3, File No. 2-98443); as supplemented by Supplemental Indentures dated as of October 1, 1987 (Designated as Exhibit 4(a) to the Current Report on Form 8-K, dated November 13, 1987, File No. 1-1910) and as of January 26, 1993 (Designated as Exhibit 4(b) to the Current Report on Form 8-K, dated January 29, 1993, File No. 1-1910.)
'4(e) -Form of Subordinated Indenture between the Company and The Bank of New York, as Trustee in connection with the issuance of the Junior Subordinated Debentures. (Designated as Exhibit 4(d) to the Registration Statement on Form S-3 dated August 5, 2003, File No. 333-107681.)
- 4(f) - Form of Supplemental Indenture between the Company and The Bank of New York, as Trustee in connection with the issuances of the Junior Subordinated Debentures. (Designated as Exhibit 4(e) to the Registration Statement on Form S-3 dated August 5, 2003, File No. 333-107681.)
94(g) - Form of Preferred Securities Guarantee (Designated as Exhibit 4(f) to the Registration Statement on Form S-3 dated August 5, 2003, File No. 333-107681.)
'4(h) - Form of Junior Subordinated Debenture (Designated as Exhibit 4(h) to the Registration Statement on Form S-3 dated August 5, 2003, File No. 333-107681.)
- 4(i) - Form of Amended and Restated Declaration of Trust (including Form of Preferred Security) (Designated as Exhibit 4(c) to the Registration Statement on Form S-3 dated August 5, 2003, File No. 333-107681.)
10(a) - Executive Annual Incentive Plan of Constellation Energy Group, Inc., as amended and restated.
(Designated as Exhibit No. 10(a) to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2004, File Nos. 1-12869 and 1-1910.)
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'10(b) - Constellation Energy Group, Inc. 1995 Long-Term Incentive Plan, as amended and restated. (Designated as Exhibit No. 10(b) to the Quarterly Report on Form I0-Q for the quarter ended September 30, 2004, File Nos. 1-12869 and 1-1910.)
10(c) - Constellation Energy Group, Inc. Nonqualified Deferred Compensation Plan, as amended and restated.
(Designated as Exhibit No. 10(c) to the Annual Report on Form 10-K for the year ended December 31, 2002, File Nos. 1-12869 and 1-1910.)
10(d) - Constellation Energy Group, Inc. Deferred Compensation Plan for Non-Employee Directors, as amended and restated.
'10(e) - Compensation agreements between Constellation Energy Group, Inc. and E. Follin Smith (Attachment I-Employment Agreement; Attachment 2-Severance Agreement). (Designated as Exhibit 10(c) to the Quarterly Report on Form I0-Q for the quarter ended June 30, 2004, File Nos.
1-12869 and 1-1910.)
- 10(f) - Change in control severance agreement between Constellation Energy Group, Inc. and Thomas V.
Brooks. (Designated as Exhibit 10(f) to the Quarterly Report on Form I0-Q for the quarter ended March 31, 2004, File Nos. 1-12869 and 1-1910.)
'10(g) - Grantor Trust Agreement Dated as of February 27, 2004 between Constellation Energy Group, Inc. and Citibank, NA (Designated as Exhibit No. 10(d) to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2004, File Nos. 1-12869 and 1-1910.)
'10(h) - Change in control severance agreement between Constellation Energy Group, Inc. and Mayo A. Shatruck 111. (Designated as Exhibit O0(e) to the Quarterly Report on Form I0-Q for the quarter ended September 30, 2004, File Nos. 1-12869 and 1-1910.)
'10(i) - Grantor Trust Agreement dated as of February 27, 2004 between Constellation Energy Group, Inc. and T. Rowe Price Trust Company. (Designated as Exhibit No. IO(b) to the Quarterly Report on Form IO-Q for the quarter ended June 30, 2004, File Nos. 1-12869 and 1-1910.)
'10(j) - Full Requirements Service Agreement between Constellation Power Source, Inc. and Baltimore Gas and Electric Company. (Designated as Exhibit No. 10(a) to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2000, File Nos. 1-12869 and 1-1910.) (Portions of this exhibit have been omitted pursuant to a request for confidential treatment.)
- 10(k) - Full Requirements Service Agreement between Constellation Power Source, Inc. and Baltimore Gas and Electric Company. (Designated as Exhibit No. 10(a) to the Quarterly Report on Form I0-Q for the quarter ended September 30, 2001, File Nos. 1-12869 and 1-1910.) (Portions of this exhibit have been omitted pursuant to a request for confidential treatment.)
'10(1) - Full Requirements Service Agreement between Baltimore Gas and Electric Company and Allegheny Energy Supply Company, LLC. (Designated as Exhibit No. 10(b) to the Quarterly Report on Form I0-Q for the quarter ended September 30, 2001, File Nos. 1-12869 and 1-1910.) (Portions of this exhibit have been omitted pursuant to a request for confidential treatment.)
- 10(m) - Consent to Assignment and Assumption Agreement by and among Allegheny Energy Supply, LLC. and Baltimore Gas and Electric Company and Constellation Power Source, Inc. (Designated as Exhibit 10(1) to the Quarterly Report on Form I0-Q for the quarter ended June 30, 2003, File Nos. 1-12869 and 1-1910.) (Portions of this exhibit have been omitted pursuant to a request for confidential treatment.)
- 10(n) - Constellation Energy Group, Inc. Benefits Restoration Plan, as amended and restated. (Designated as Exhibit No. 10(m) to the Annual Report on Form 10-K for the year ended December 31, 2001, File Nos. 1-12869 and 1-1910.)
- 10(o) - Constellation Energy Group, Inc. Supplemental Pension Plan, as amended and restated. (Designated as Exhibit No. IO(d) to the Quarterly Report on Form I0-Q for the quarter ended March 31, 2004, File Nos. 1-12869 and 1-1910.)
- 10(p) - Constellation Energy Group, Inc. Senior Executive Supplemental Plan, as amended and restated.
(Designated as Exhibit No. IO(e) to the Quarterly Report on Form I0-Q for the quarter ended March 31, 2004, File Nos. 1-12869 and 1-1910.)
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- 10(q) - Constellation Energy Group, Inc. Supplemental Benefits Plan, as amended and restated. (Designated as Exhibit No. 10(p) to the Annual Report on Form 10-K for the year ended December 31, 2001, File Nos. 1-12869 and 1-1910.)
- 10(r) - Change in control severance agreement between Constellation Energy Group, Inc. and Michael J.
Wallace. (Designated as Exhibit 10(f) to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2004, File Nos. 1-12869 and 1-1910.)
10(s) - Change in control severance agreement between Constellation Energy Group, Inc. and Thomas F. Brady.
'10(r) - Constellation Energy Group, Inc. Executive Long-Term Incentive Plan, as amended and restated.
(Designated as Exhibit 10(d) to the Quarterly Report on Form 10-Q for the quarter ended September 30. 2004, File Nos. 1-12869 and 1-1910.)
'10(u) - Constellation Energy Group, Inc. 2002 Executive Annual Incentive Plan, as amended and restated.
(Designated as Exhibit 10(h) to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2004, File Nos. 1-12869 and 1-1910.)
'10(v) - Constellation Energy Group, Inc. 2002 Senior Management Long-Term Incentive Plan, as amended and restated. (Designated as Exhibit 10(c) to the Quarterly Report on Form I0-Q for the quarter ended September 30, 2004, File Nos. 1-12869 and 1-1910.)
- 10(w) - Constellation Energy Group, Inc. Management Long-Term Incentive Plan, as amended and restated.
(Designated as Exhibit 10(a) to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2004, File Nos. 1-12869 and 1-1910.)
10(x) - Summary of Constellation Energy Group, Inc. Board of Directors 2005 Non-Employee Director Compensation Program.
12(a) - Constellation Energy Group, Inc. and Subsidiaries Computation of Ratio of Earnings to Fixed Charges.
12(b) - Baltimore Gas and Electric Company and Subsidiaries Computation of Ratio of Earnings to Fixed Charges and Computation of Ratio of Earnings to Combined Fixed Charges and Preferred and Preference Dividend Requirements.
21 - Subsidiaries of the Registrant.
23 - Consent of PricewaterhouseCoopers LLP, Independent Registered Public Accounting Firm.
31(a) - Certification of Chairman of the Board, Chief Executive Officer and President of Constellation Energy Group, Inc. pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31(b) - Certification of Executive Vice President and Chief Financial Officer of Constellation Energy Group, Inc.
pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31(c) - Certification of President and Chief Executive Officer of Baltimore Gas and Electric Company pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31(d) - Certification of Senior Vice President and Chief Financial Officer of Baltimore Gas and Electric Company pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32(a) - Certification of Chairman of the Board, Chief Executive Officer and President of Constellation Energy Group, Inc. pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32(b) - Certification of Executive Vice President and Chief Financial Officer of Constellation Energy Group, Inc.
pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32(c) - Certification of President and Chief Executive Officer of Baltimore Gas and Electric Company pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32(d) - Certification of Senior Vice President and Chief Financial Officer of Baltimore Gas and Electric Company pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
124
CONSTELLATION ENERGY GROUP, INC. AND SUBSIDIARIES AND BALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARIES SCHEDULE II-VALUATION AND QUALIFYING ACCOUNTS Column A Column B Column C Column D Column E Additions Balance Charged Charged to at to costs Olt Ier Balance at beinning and Accounts- (Deductions)- end of Description oflperiod expenses Describe Describe period (In mixons)
Reserves deducted in the Balance Sheet from the assets to which they apply:
Constellation Energy Accumulated Provision for Uncollectibles 2004 S 51.7 $22.2 $ (30.8)(A) $ 43.1 2003 41.9 22.0 (12.2)(A) 51.7 2002 22.8 26.4 12.5 (B) (19.8)(A) 41.9 Valuation Allowance-Net unrealized (gain) loss on available for sale securities 2004 _ - 0.1 (C) 0.1 2003 2002 (243.7) - 243.7 (C)
Net unrealized (gain) loss on nuclear decommissioning trust funds 2004 (13.7) (59.6)(C) (73.3) 2003 47.4 (61.1)(C) (13.7) 2002 (21.0) 68.4 (C) 47.4 BGE Accumulated Provision for Uncollectibles 2004 10.7 16.3 (14.0)(A) 13.0 2003 11.5 9.0 (9.8)(A) 10.7 2002 13.4 14.5 (16.4)(A) 11.5 (A) Represents principally net amounts charged off as uncollectible.
(B) Represents amounts acquired resulting from our acquisitions of NewEnergy and Alliance.
(C) Represents amounts recorded in or reclassified from accumulated other comprehensive income.
125
SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, Constellation Energy Group, Inc., the Registrant, has duly caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized.
CONSTELLATION ENERGY GROUP, INC.
(REGISTRANT)
Date: March 11, 2005 By Isl MAYO A. SHATTUCK III Mayo A. Shattuck III Chairman of the Board, ChiefExecutive Officer and President Pursuant to the requirements of the Securities Exchange Act of 1934, this Report has been signed below by the following persons on behalf of Constellation Energy Group, Inc., the Registrant, and in the capacities and on the dates indicated.
Signature Tilde Date Principal executive officer and director:
By Isl M. A. Shattuck III Chairman of the Board, Chief March 11, 2005 M. A. Shattuck III Executive Officer, President and Director Principal financial and accounting officer:
By Isl E. F. Smith Executive Vice President, Chief March 11, 2005 E. F. Smith Financial Officer, and Chief Administrative Officer Directors:
IsI Y. C. de Balmann Director March 11, 2005 Y. C. de Balmann Isi D. L Becker Director March 11, 2005 D. L Becker IsI J. T. Brady Director March 11, 2005 J. T. Brady Is! E P. Bramble, Sr. Director March 11, 2005 F. P. Bramble, Sr.
/s/ E. A. Crooke Director March 11, 2005 E. A. Crooke
/s! J. R. Curtiss Director March 11, 2005 J. R. Curtiss 126
Signature Tide Date
/SI R W. Gale Director March II, 2005 R. NV. Gale Is- F. A. Hrabowski, III Director March II, 2005 F. A. Hrabowski, III
/s/ E. J. Kelly, Ill Director March 11, 2005 E. J. Kelly, Ill
/s/ N. Lampton Director March II, 2005 N. Lampton
/sI R-. Lawless Director March 11 , 2005 R. 3.Lawless
'S5 L M. Martin Director March 11, 2005 L M. Martin I/s M. D. Sullivan Director March II, 2005 M. D. Sullivan 127
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, Baltimore Gas and Electric Company, the Registrant, has duly caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized.
BALTIMORE GAS AND ELECTRIC COMPANY (REGISTRANT)
Date: March I1I, 2005 By Isl KENNETH W. DEFoNTES, JR.
Kenneth W. DeFontes, Jr.
President and ChiefExecutive Officer Pursuant to the requirements of the Securities Exchange Act of 1934, this Report has been signed below by the following persons on behalf of Baltimore Gas and Electric Company, the Registrant, and in the capacities and on the dates indicated.
Signature Title Date Principal executive officer and director By IAl K. W. DeFontes, Jr. President, Chief Executive March 11, 2005 K. W. DeFontes, Jr. Officer, and Director Principal financial and accounting officer and director:
By Isl E. E Smith Senior Vice President. Chief March 11, 2005 E. F. Smith Financial Officer, and Director Directors:
Isi M. A. Shattuck III Director March 11, 2005 M. A. Shattuck III 128
Exhibit 31(a)
CONSTELLATION ENERGY GROUP, INC.
CERTIFICATION I, Mayo A. Shattuck 111, certify that:
- 1. I have reviewed this report on Form 10-K of Constellation Energy Group, Inc.;
- 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
- 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
- 4. The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; (b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; (c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and (d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
- 5. The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's Board of Directors (or persons performing the equivalent functions):
(a) Ail significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and (b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
Date: March 11, 2005 Isl MAYO A. SHATTUCK III Chairman of the Board, Chief Executive Officer, and President
Exhibit 31(b)
CONSTELLATION ENERGY GROUP, INC.
CERTIFICATION 1, E. Follin Smith, certify that:
- 1. I have reviewed this report on Form 10-K of Constellation Energy Group, Inc.;
- 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
- 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
- 4. The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; I (b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; (c) Evaluated the effectiveness of the registrants disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and (d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
- 5. The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's Board of Directors (or persons performing the equivalent functions):
(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and (b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
Date: March 11, 2005 Isl E. FoLUN SMrrH Executive Vice President, Chief Financial Officer, and Chief Administrative Officer
Exhibit 311c)
BALTIMORE GAS AND ELECTRIC COMPANY CERTIFICATION 1, Kenneth W. DeFontes, Jr., certify that:
- 1. I have reviewed this report on Form 10-K of Baltimore Gas and Electric Company,
- 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
- 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
- 4. The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and ISd-15(e)) for the registrant and have:
(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; (b) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and (c) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
- 5. The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's Board of Directors (or persons performing the equivalent functions):
(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and (b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
Date: March 11, 2005 Isl KENNETHWV. DEFONTES, JR.
President and Chief Executive Officer
Exhibit 31(d)
BALTIMORE GAS AND ELECTRIC COMPANY CERTIFICATION I, E. Follin Smith, certify that:
- 1. I have reviewed this report on Form 10-K of Baltimore Gas and Electric Company;
- 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
- 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
- 4. The registrants other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:
(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; (b) Evaluated the effectiveness of the registrants disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and (c) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting: and
- 5. The registrants other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's Board of Directors (or persons performing the equivalent functions):
(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and (b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
Date: March 11, 2005 Isl E. FOLUN SMITH Senior Vice President and Chief Financial Officer
Exhibit 32(a)
CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350 AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 I, Mayo A. Shattuck 111, Chairman of the Board, Chief Executive Officer and President of Constellation Energy Group, Inc., certify pursuant to 18 U.S.C. Section 1350 adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 that to my knowledge:
(i) The accompanying Annual Report on Form 10-K for the year ended December 31, 2004 fully complies with the requirements of Section 13(a) or Section 15(d) of the Securities Exchange Act of 1934, as amended; and (ii) The information contained in such report fairly presents, in all material respects, the financial condition and results of operations of Constellation Energy Group, Inc.
Isl MAYO A. SHArTUCK III Mayo A. Shattuck IlI Chairman of the Board, Chief Executive Officer, and President Date: March 11, 2005
Exhibit 32(b)
CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350 AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 I. E. Follin Smith, Executive Vice President, Chief Financial Officer, and Chief Administrative Officer of Constellation Energy Group, Inc., certify pursuant to 18 U.S.C. Section 1350 adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 that to my knowledge:
(i) The accompanying Annual Report on Form 10-K for the year ended December 31, 2004 fully complies with the requirements of Section 13(a) or Section 15(d) of the Securities Exchange Act of 1934, as amended; and (ii) The information contained in such report fairly presents, in all material respects, the financial condition and results of operations of Constellation Energy Group, Inc.
Isl E. FOlLIN SMrrH E. Follin Smith Executive Vice President, Chief Financial Officer, and Chief Administrative Officer Date: March 11, 2005
Exhibit 32(c)
CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350 AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 1, Kenneth W. DeFontes, Jr., President and Chief Executive Officer of Baltimore Gas and Electric Company, certify pursuant to 18 U.S.C. Section 1350 adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 that to my knowledge:
(i) The accompanying Annual Report on Form 10-K for the year ended December 31, 2004 fully complies with the requirements of Section 13(a) or Section 15(d) of the Securities Exchange Act of 1934, as amended; and (ii) The information contained in such report fairly presents, in all material respects, the financial condition and results of operations of Baltimore Gas and Electric Company.
Isl KENNMI W. DEFoNTEs, JRa Kenneth W. DeFontes, Jr.
President and Chief Executive Officer Date: March 11, 2005
Exhibit 32(d)
CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350 AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 1, E. Follin Smith, Senior Vice President and Chief Financial Officer of Baltimore Gas and Electric Company, certify pursuant to 18 U.S.C. Section 1350 adopted pursuant to Section 906 of the Sarbanes-Oxiey Act of 2002 that to my knowledge:
(i) The accompanying Annual Report on Form 10-K for the year ended December 31, 2004 fully complies with the requirements of Section 13(a) or Section 15(d) of the Securities Exchange Act of 1934, as amended; and (ii) The information contained in such report fairly presents, in all material respects, the financial condition and results of operations of Baltimore Gas and Electric Company.
Is/ E. FoLLIN SMITH E. Follin Smith Senior Vice President and Chief Financial Officer Date: March 11, 2005