UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the Quarterly Period Ended June 30, 2002
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
Exhibit 99.1
Certificate Pursuant to Section 1350
of Chapter 63 of Title 18 United States Code
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The undersigned officers hereby certify, as to the Quarterly Report on
Form 10-Q of Exelon Corporation for the quarterly period ended June 30, 2002,
that (i) the report fully complies with the requirements of section 13(a) or
15(d) of the Securities Exchange Act of 1934, as amended, and (ii) the
information contained in the report fairly presents, in all material respects,
the financial condition and results of operations of Exelon Corporation and its
subsidiaries.
Date: August 6, 2002 /s/ John W. Rowe
----------------
John W. Rowe
Chairman and Chief Executive Officer
Exelon Corporation
Date: August 2, 2002 /s/ Ruth Ann M. Gillis
--------------------------------
Ruth Ann M. Gillis
Senior Vice President and Chief Financial Officer
Exelon Corporation
Exhibit 99.2
Certificate Pursuant to Section 1350
of Chapter 63 of Title 18 United States Code
--------------------------------------------
The undersigned officer hereby certifies, as to the Quarterly Report on
Form 10-Q of Commonwealth Edison Company for the quarterly period ended June 30,
2002, that (i) the report fully complies with the requirements of section 13(a)
or 15(d) of the Securities Exchange Act of 1934, as amended, and (ii) the
information contained in the report fairly presents, in all material respects,
the financial condition and results of operations of Commonwealth Edison Company
and its subsidiaries.
Date: August 6, 2002 /s/ Frank M. Clark
---------------------------------
Frank M. Clark
President (Chief Executive Officer)
Commonwealth Edison Company
Exhibit 99.3
Certificate Pursuant to Section 1350
of Chapter 63 of Title 18 United States Code
--------------------------------------------
The undersigned officer hereby certifies, as to the Quarterly Report on
Form 10-Q of Commonwealth Edison Company for the quarterly period ended June 30,
2002, that (i) the report fully complies with the requirements of section 13(a)
or 15(d) of the Securities Exchange Act of 1934, as amended, and (ii) the
information contained in the report fairly presents, in all material respects,
the financial condition and results of operations of Commonwealth Edison Company
and its subsidiaries.
Date: August 2, 2002 /s/ Robert E. Berdelle
------------------------------
Robert E. Berdelle
Vice President, Finance and Chief Financial Officer
Commonwealth Edison Company
Exhibit 99.4
Certificate Pursuant to Section 1350
of Chapter 63 of Title 18 United States Code
--------------------------------------------
The undersigned officer hereby certifies, as to the Quarterly Report on
Form 10-Q of PECO Energy Company for the quarterly period ended June 30, 2002,
that (i) the report fully complies with the requirements of section 13(a) or
15(d) of the Securities Exchange Act of 1934, as amended, and (ii) the
information contained in the report fairly presents, in all material respects,
the financial condition and results of operations of PECO Energy Company and its
subsidiaries.
Date: August 6, 2002 /s/ Kenneth G. Lawrence
-----------------------
Kenneth G. Lawrence
President (Chief Executive Officer)
PECO Energy Company
Exhibit 99.5
Certificate Pursuant to Section 1350
of Chapter 63 of Title 18 United States Code
--------------------------------------------
The undersigned officer hereby certifies, as to the Quarterly Report on
Form 10-Q of PECO Energy Company for the quarterly period ended June 30, 2002,
that (i) the report fully complies with the requirements of section 13(a) or
15(d) of the Securities Exchange Act of 1934, as amended, and (ii) the
information contained in the report fairly presents, in all material respects,
the financial condition and results of operations of PECO Energy Company and its
subsidiaries.
Date: July 31, 2002 /s/ Frank F. Frankowski
--------------------------------
Frank F. Frankowski
Vice President, Finance and Chief Financial Officer
PECO Energy Company
Exhibit 99.6
Certificate Pursuant to Section 1350
of Chapter 63 of Title 18 United States Code
--------------------------------------------
The undersigned officer hereby certifies, as to the Quarterly Report on
Form 10-Q of Exelon Generation Company, LLC for the quarterly period ended June
30, 2002, that (i) the report fully complies with the requirements of section
13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, and (ii) the
information contained in the report fairly presents, in all material respects,
the financial condition and results of operations of Exelon Generation Company,
LLC and its subsidiaries.
Date: August 5, 2002 /s/ Oliver D. Kingsley, Jr.
---------------------------
Oliver D. Kingsley, Jr.
CEO and President (Chief Executive Officer)
Exelon Generation Company, LLC
Exhibit 99.7
Certificate Pursuant to Section 1350
of Chapter 63 of Title 18 United States Code
--------------------------------------------
The undersigned officer hereby certifies, as to the Quarterly Report on
Form 10-Q of Exelon Generation Company, LLC for the quarterly period ended June
30, 2002, that (i) the report fully complies with the requirements of section
13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, and (ii) the
information contained in the report fairly presents, in all material respects,
the financial condition and results of operations of Exelon Generation Company,
LLC and its subsidiaries.
Date: August 2, 2002 /s/ Ruth Ann M. Gillis
----------------------
Ruth Ann M. Gillis
Chief Financial Officer
Exelon Generation Company, LLC
Exhibit 99.8
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Results of Operations
Year Ended December 31, 2001 Compared to Year Ended December 31, 2000
Net Income. Our net income increased $264 million, or 102%, for 2001. Income before cumulative effect of changes in accounting principles increased $252 million, or 97%, for 2001.
Earnings Before Interest and Income Taxes. We and our parent Exelon evaluate our performance based on earnings before interest and income taxes (EBIT). In addition to components of operating income as shown on the consolidated statements of income, EBIT includes equity in earnings of unconsolidated affiliates, and other income and expense recorded in other, net, with the exception of investment income.
The October 20, 2000 merger of PECO and Unicom, and the January 1, 2001 corporate restructuring, significantly impacted our results of operations. To provide a more meaningful analysis of results of operations, the EBIT analyses below identifies the portion of the EBIT variance that is attributable to the former ComEd generation business unit results of operations and the portion of the variance that results from normal operations attributable to changes in components of our underlying operations. The merger variance represents the former ComEd generation business unit results for the year ended December 31, 2000 prior to the October 20, 2000 acquisition date as well as the effect of merger-related costs incurred in 2000. The 2000 effects of the merger and restructuring were developed using estimates of various items, including allocation of corporate overheads and intercompany transactions.
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Components of Variance |
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2001 |
2000 |
Variance |
Merger Variance |
Normal Operations |
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(in millions) |
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| Operating Revenue | $ | 7,048 | $ | 3,274 | $ | 3,774 | $ | 2,772 | $ | 1,002 | ||||||
| Fuel & Purchased Power | 4,218 | 1,846 | 2,372 | 1,689 | 683 | |||||||||||
| Operating & Maintenance and Other | 1,586 | 858 | 728 | 978 | (250 | ) | ||||||||||
| Depreciation & Decommissioning | 282 | 123 | 159 | 83 | 76 | |||||||||||
| EBIT | $ | 962 | $ | 447 | $ | 515 | $ | 22 | $ | 493 | ||||||
Our EBIT increased $515 million for 2001 compared to 2000. This increase was primarily attributable to higher margins on increased market and affiliate wholesale energy sales, coupled with reduced operating expenses at the nuclear plants, partially offset by additional depreciation and decommissioning expense. During the first five months of 2001, we benefited from increases in wholesale market prices, particularly in the Pennsylvania-New Jersey-Maryland control area and Mid-America Interconnected Network regions. The increase in wholesale market prices was primarily driven by significant increases in fossil fuel prices. The large concentration of nuclear generation in our portfolio allowed us to capture the higher prices in the wholesale market for sales to non-affiliates with minimal increase in fuel prices. Our revenues for 2001 include charges to affiliates for line losses. Line loss charges were not included in 2000 revenue. We also benefited from higher nuclear plant output due to increased capacity factors during 2001. Energy marketing activities positively impacted 2001 results. Mark-to-market gains were $16 million and $14 million on non-trading and trading energy contracts, respectively, offset by realized trading losses of $6 million.
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Our sales were 201,879 GWhs in 2001 compared to 200,072 GWhs in 2000, approximately 60% of which were to affiliates. Supply sources for 2001 and 2000 were as follows:
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2001 |
2000 |
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|---|---|---|---|---|---|
| Operated nuclear units | 54 | % | 54 | % | |
| Purchases | 37 | % | 37 | % | |
| Fossil and hydro units | 3 | % | 3 | % | |
| Generation investments | 6 | % | 6 | % | |
| Total | 100 | % | 100 | % |
Our nuclear fleet, including AmerGen, performed at a weighted average capacity factor of 94.4% for 2001 compared to 93.8% in 2000. Our nuclear fleet's production costs, including AmerGen, were $12.79 per MWh for 2001, compared to $14.65 per MWh for 2000. Our purchased power costs were $42.26 MWh for 2001, compared to $38.05 per MWh for 2000. The increase resulted in purchase power costs from the increase in fuel prices in the first quarter of 2001 as well as the increase in volumes sold during peak demand in 2001 compared to 2000.
Operating expenses were favorably affected by reductions in labor costs due to a decline in the number of employees and fewer nuclear outages in 2001 than in 2000, which offset the effect of increases in litigation-related expenses of $30 million. In addition, our EBIT benefited from an increase in equity in earnings of AmerGen and Sithe of $86 million in 2001 compared to the prior-year period reflecting a full year of operations for Sithe and AmerGen's Oyster Creek plant in 2001.
The increase in depreciation and decommissioning expense is primarily due to an increase in decommissioning expense of $140 million resulting from the discontinuance of regulatory accounting practices associated with decommissioning costs for the former ComEd nuclear generating stations that are in active generation, partially offset by a $90 million reduction in depreciation and decommissioning expense attributable to the extension of estimated service lives of our generating plants.
Other Components of Net Income
Interest Expense. Interest expense increased $74 million in 2001, from $41 million, in 2000. This increase was primarily attributable to increased interest charge on the note payable to Exelon of $23 million, interest charges of $26 million due to the issuance of $700 million of 6.95% senior unsecured notes in a 144A offering in June 2001, $23 million of additional interest due to a full year of interest charges on the spent fuel obligation compared to only two months in 2000 for the former ComEd generating stations and $15 million of interest charges from affiliates. These increases were partially offset by capitalized interest of approximately $17 million.
Investment Income. Investment income is recorded in Other, Net on the Consolidated Statements of Income, but is excluded from EBIT. Investment income decreased by $29 million due to net realized losses of $127 million offset by interest and dividend income of $67 million on the nuclear decommissioning trust funds reflecting the discontinuance of regulatory accounting practices associated with nuclear decommissioning costs for the nuclear stations formerly owned by ComEd, primarily offset by increased income of $31 million of money market interest and interest on the loan to Sithe recorded in 2001.
Income Taxes. The effective income tax rate was 39.0% for 2001 as compared to 38.1% for 2000. The increase in the effective income tax rate was primarily attributable to a higher effective state income rate due to operations in Illinois subsequent to the merger and a reduction in the investment tax credit. Income taxes increased by $167 million in 2001 as compared to 2000, $160 million of which is due to higher pretax income and $7 million due to a higher effective income tax rate.
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Cumulative Effect of Changes in Accounting Principles
On January 1, 2001, we adopted Statement of Financial Accounting Standards No. 133 "Accounting for Derivative Instruments and Hedging Activities" (SFAS No. 133), as amended, resulting in a benefit of $12 million, net of income taxes.
Year Ended December 31, 2000 Compared to Year Ended December 31, 1999
Net Income. Our net income increased $56 million, or 27%, in 2000.
Earnings Before Interest and Income Taxes. To provide a more meaningful analysis of our results of operations, the EBIT analysis below identifies the portion of the EBIT variance that is attributable to the former ComEd generation business unit results of operations and the portion of the variance that results from normal operations attributable to changes in components of our underlying operations. The merger variance represents the former ComEd generation business unit results for the period after October 20, 2000 as well as the effect of merger-related costs incurred in 2000. The 2000 and 1999 results also reflect the corporate restructuring as if it had occurred on January 1, 1999. The 2000 effects of the merger and restructuring were developed using estimates of various items, including allocation of corporate overheads and intercompany transactions.
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Components of Variance |
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|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
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2000 |
1999 |
Variance |
Merger Variance |
Normal Operations |
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(in millions) |
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| Operating Revenue | $ | 3,274 | $ | 2,425 | $ | 849 | $ | 561 | $ | 288 | ||||||
| Fuel & Purchased Power | 1,846 | 1,205 | 641 | 279 | 362 | |||||||||||
| Operating Expense and Other | 858 | 765 | 93 | 180 | (87 | ) | ||||||||||
| Depreciation & Decommissioning | 123 | 125 | (2 | ) | 31 | (33 | ) | |||||||||
| EBIT | $ | 447 | $ | 330 | $ | 117 | $ | 71 | $ | 46 | ||||||
Our EBIT increased $117 million for 2000 compared to 1999. The merger accounted for $71 million of the variance. The remaining $46 million increase resulted primarily from higher margins on market and affiliate wholesale energy sales, a charge against earnings of $15 million related to the abandonment of two information systems implementations in 1999 and a $15 million write-off in 1999 of the investment in a cogeneration facility in connection with the settlement of litigation. Our EBIT benefited from an increase in equity in earnings of AmerGen of $4 million in 2000 compared to the prior-year period. Effective with the acquisition of Clinton Nuclear Power Station by AmerGen, our agreement to manage Clinton was terminated, resulting in lower revenues of $99 million and lower operating and maintenance expense of $70 million.
Our nuclear fleet, including AmerGen, performed at a weighted average capacity factor of 93.8% for 2000. Our nuclear fleet production costs for 2000, including AmerGen, were $14.65 per MWh. Our purchased power costs for 2000 were $38.05 per MWh.
Other Components of Net Income
Interest Expense. Interest expense increased $29 million, or 242%, to $41 million in 2000. The increase was primarily attributable to interest related to the spent fuel obligation of the former ComEd nuclear plants, which was assumed in connection with the merger, and interest expense related to the $696 million note payable to Exelon used to finance our investment in Sithe.
Income Taxes. The effective tax rate was 38.1% in 2000 as compared to 38.0% in 1999.
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Liquidity and Capital Resources
Our capital resources are primarily provided by internally generated cash flows from operations and, to the extent necessary, external financings and borrowings or capital contributions from Exelon. Our access to external financing at reasonable terms is dependent on our credit ratings and our general business condition, as well as the general business conditions of the industry. Our business is capital intensive. Capital resources are used primarily to fund our capital requirements, including construction, investments in new and existing ventures, and repayments of maturing debt. Any potential future acquisitions could require external financing or borrowings or capital contributions for Exelon.
Cash Flows from Operating Activities. Cash flows provided by operations for 2001 were $1.3 billion. Our cash flows from operating activities primarily result from the sale of electric energy to wholesale customers, including our affiliated companies. Our future cash flow from operating activities will depend upon future demand and market prices for energy and the ability to continue to produce and supply power at competitive costs.
Cash Flows from Investing Activities. Cash flows used in investing activities for 2001 were $1.1 billion, primarily for capital expenditures of $515 million, investment in nuclear fuel of $336 million and $239 million related to our investment in the nuclear decommissioning funds. We project capital expenditures of approximately $1.1 billion in 2002, approximately 75% of which are for additions to and upgrades of existing facilities, nuclear fuel and increases in capacity at existing plants. Capital expenditures are projected to increase in 2002 as compared to 2001 due to higher nuclear fuel expenditures, growth and an increase in the number of planned refueling outages, during which significant maintenance work is performed. Eleven nuclear refueling outages, including AmerGen, are planned for 2002, compared to six during 2001. Total capital expenditures during nuclear refueling outages are expected to increase in 2002 over 2001 by $24 million. We anticipate that our capital expenditures will be funded by internally generated funds, external borrowings, and borrowings or capital contributions from Exelon. Our proposed capital expenditures and other investments are subject to periodic review and revision to reflect changes in economic conditions and other factors.
In addition to the 2002 capital expenditures of $1.1 billion, we expect to close the purchase of two natural-gas and oil-fired plants from TXU Corp. (TXU) in the second quarter of 2002. The $443 million purchase is expected to be funded with available cash and borrowings from Exelon.
During 2001, we loaned Sithe $150 million, which was repaid by Sithe in December of 2001. During 2001, Sithe paid us $2 million in interest on the loan.
Cash Flows from Financing Activities. Cash flows used in financing activities were $1 million in 2001 primarily attributable to the issuance of $700 million of senior unsecured notes with a maturity of June 2011 The majority of the proceeds of this issuance were used to repay Exelon for amounts borrowed to finance our investment in Sithe. We also issued $121 million of pollution control bonds to refinance an equivalent amount originally issued by PECO.
Credit Issues. We meet short-term liquidity requirements primarily through internally generated cash or borrowings from Exelon. We, along with ComEd, PECO and Exelon, entered into a $1.5 billion unsecured revolving credit facility with a group of banks. We currently cannot borrow under the credit agreement until we deliver audited financial statements to the banks, which is expected to occur in the second quarter of 2002. At December 31, 2001, we had outstanding $700 million of 6.95% senior unsecured debt, $317 million of variable rate pollution control notes and other long-term notes payable of $9 million. For 2001, the average interest rate on these pollution control notes was approximately 2.62% Certain of the credit agreements to which we are party require us to maintain a debt to total capitalization ratio of 65% or less. At December 31, 2001, our debt to total capitalization ratio on that basis was 35%.
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Our access to the capital markets and financing costs in those markets is dependent on our securities ratings. None of our borrowings are subject to default or prepayment as a result of a downgrading of securities ratings, although such a downgrading could increase interest charges under the bank credit facility. We enter agreements to purchase energy and capacity, including obligations that are treated as derivatives, which require us to maintain investment grade ratings. Failure to maintain investment grade ratings would allow a counterparty to terminate its contract and settle the transaction on a net present value basis. Exelon has provided guarantees to support certain of our lines of credit, surety bonds, nuclear insurance and energy marketing contracts.
Exelon has obtained an order from the SEC under PUHCA authorizing financing transactions, including the issuance of common stock, preferred securities, long-term debt and short-term debt in an aggregate amount not to exceed $4 billion. The order applies to our issuances as well. As of December 31, 2001, $3.0 billion of financing authority was available under the SEC order. Exelon requested, and the SEC reserved jurisdiction over, an additional $4 billion in financing authorization. Exelon agreed to limit its short-term debt outstanding to $3 billion of the $4 billion total financing authority. Exelon has asked the SEC to eliminate the short-term debt restriction. The SEC order also authorized Exelon to issue guarantees of up to $4.5 billion outstanding at any one time. At December 31, 2001, Exelon had provided $1.4 billion of guarantees. Under PUHCA and the Federal Power Act, we can pay dividends only from retained or current earnings. At December 31, 2001, we had retained earnings of $524 million. Exelon is also limited by order of the SEC under PUHCA to an aggregate investment of $4 billion in exempt wholesale generators (EWGs) and foreign utility companies (FUCOs). Exelon requested, and the SEC reserved jurisdiction over, an additional $1.5 billion investment in EWGs and FUCOs.
Contractual Obligations and Commercial Commitments. Our contractual obligations and commercial commitments as of December 31, 2001 are as follows:
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Payment Due Within |
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| Obligations/Commitments |
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Due After 5 Years |
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| Total |
1 Year |
2-3 Years |
4-5 Years |
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($ in millions) |
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| Long-Term Debt(a) | $ | 1,025 | $ | 4 | $ | 5 | $ | — | $ | 1,016 | |||||
| Operating Leases(b) | 682 | 28 | 63 | 64 | 527 | ||||||||||
| Purchase Power Obligations(c) | 12,192 | 1,695 | 3,173 | 1,346 | 5,978 | ||||||||||
| Acquisition of TXU Generating Stations(d) | 443 | 443 | — | — | — | ||||||||||
| Spent fuel obligation(e) | 843 | — | — | — | 843 | ||||||||||
- (a)
- Comprised
primarily of senior unsecured debt and pollution control notes. In connection with the variable rate debt, we maintain direct pay letters of credit in order to provide
liquidity in the event that it is not possible to remarket all of the debt as required following specific events, including changes in the basis of determining the interest rate of debt. Letters of
credit as of December 31, 2001 amounted to $317 million, of which $121 million expire in 2002 and the remaining $196 million expire in 2003 to 2004. Total includes the
current portion of long-term debt.
- (b)
- Company
leases equipment and certain office facilities.
- (c)
- Commitments
relating to the purchase of energy, capacity and transmission rights. Included in amounts are $3,485 million of power purchases from our affiliate AmerGen.
- (d)
- Commitment
to purchase generating stations in spring of 2002.
- (e)
- One-time fee of $277 million with interest to date payable to the DOE for Spent Nuclear Fuel.
We have an obligation to decommission our nuclear power plants. Our current estimate of decommissioning costs for our owned nuclear plants is $7.2 billion in current-year (2002) dollars.
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Nuclear decommissioning activity occurs primarily after a plant's retirement and is currently estimated to begin in 2029, except for the retired Zion station, which is currently estimated to begin decommissioning in 2013. Decommissioning costs are recoverable by ComEd and PECO through regulated rates and are remitted to us for deposit in the decommissioning trust funds. In 2001, ComEd and PECO collected from customers and remitted to us approximately $102 million in decommissioning costs. At December 31, 2001, the decommissioning liability, which is recorded over the life of the plant, recorded in Property, Plant and Equipment, Net as well as Deferred Credits and Other Liabilities on our balance sheet was $2.7 billion and $1.3 billion, respectively. In order to fund future decommissioning costs, we held $3.2 billion of investments in nuclear decommissioning trust funds, which are included as Deferred Debits and Other Assets on our balance sheet and which include net unrealized and realized gains. Due to the performance of the United States debt and equity markets in 2001, the value of assets held in trusts to satisfy the obligations of the nuclear generating stations eventual decommissioning has decreased. Contributions to the nuclear decommissioning trust funds of $112 million offset net losses of $109 million, resulting in a 2% increase in the decommissioning trust funds balance at December 31, 2001 compared to December 31, 2000. We believe that the amounts being remitted to us by ComEd and PECO and the earnings on nuclear decommissioning trust funds will be sufficient to fully fund our decommissioning obligations.
Off Balance Sheet Obligations. Beginning December 18, 2002, we will have the right to purchase all (but not less than all) of the remaining outstanding shares of the Sithe common stock. The option expires on December 18, 2005. In addition, each of Sithe's other stockholder groups will have the right to require us to purchase all (but not less than all) of its shares during the same period in which we can exercise our option. At the end of that period, if no stockholder has exercised its option, we will have a one-time option to purchase shares from the other stockholders to bring our holdings to 50.1% of the total outstanding shares. If we exercise our option or if all the stockholder groups exercise their put rights, the purchase price for 70% of the remaining 50.1% of the Sithe stock will be set at a fair market value plus a 10% premium in the case of a call or 10% discount in the case of a put, subject to a floor of $430 million and a ceiling of $650 million, and the remaining portion will be valued at fair market value subject to floor price of $141 million and a ceiling price of $330 million, plus, in each case, interest accrued from the beginning of the exercise period.
If we increase our ownership in Sithe to 50.1% or more, Sithe will become a consolidated subsidiary and our financial results will include Sithe's financial results from the date of purchase. At December 31, 2001, Sithe had total assets of $4.2 billion and long-term debt of $2.3 billion, including $2.1 billion of non-recourse project debt and excluding $107 million of non-recourse project debt associated with Sithe's equity investments. For the year ended December 31, 2001 Sithe had revenues of $1 billion. As of December 31, 2001, we had a $725 million equity investment in Sithe.
Additionally, the debt on the books of our unconsolidated equity investments and joint ventures is not reflected on our Consolidated Balance Sheets. Total investee debt, including the debt of Sithe described in the preceding paragraph, is currently estimated to be $2.4 billion ($1.2 billion based on Exelon Generation's ownership interest of the investments).
We and British Energy, our joint venture partner in AmerGen, have each agreed to provide up to $100 million to AmerGen at any time for operating expenses. We have committed to provide AmerGen with capital contributions equivalent to 50% of the purchase price of any acquisitions AmerGen makes in 2002.
Quantitative and Qualitative Disclosures About Market Risk
We are exposed to market risks associated with commodity price, credit, interest rates and equity prices. The inherent risk in market sensitive instruments and positions is the potential loss arising from adverse changes in commodity prices, counterparty credit, interest rates and equity security prices.
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Exelon's corporate Risk Management Committee (RMC) sets forth risk management philosophy and objectives through a corporate policy, and establishes procedures for risk assessment, control and valuation, counterparty credit approval, and the monitoring and reporting of derivative activity and risk exposures. The RMC is chaired by Exelon's chief risk officer and includes the chief financial officer, general counsel, treasurer, vice president of corporate planning and officers from each of the Exelon business units. The RMC reports to the Exelon Board of Directors on the scope of our derivative and risk management activities.
Commodity Price Risk. Commodity price risk is associated with market price movements resulting from excess or insufficient generation, changes in fuel costs, market liquidity and locational price commodity differences. Trading activities and non-trading marketing activities include the purchase and sale of electric capacity and energy and fossil fuels, including oil, gas and coal. The availability and prices of energy and energy-related commodities are subject to fluctuations due to factors such as weather, environmental policies, changes in supply and demand, state and federal regulatory policies and other events.
Marketing (non-trading) activities. To the extent that our generation supply (either owned or contracted) is in excess of our obligations to customers, including ComEd's and PECO's retail load, the available electricity is sold in the wholesale markets. To reduce price risk caused by market fluctuations, we enter into derivative contracts, including forwards, futures, swaps, and options with approved counterparties, to hedge our anticipated exposures. Market price risk exposure is the risk of a change in the value of unhedged positions. We expect to maintain a minimum 80% hedge ratio in 2002 for our energy marketing portfolio. This hedge ratio represents the percentage of our forecasted aggregate annual generation supply that is committed to firm sales, including sales to our affiliated entities. The hedge ratio is not fixed and will vary from time to time depending upon market conditions, demand and volatility. Absent any opportunistic efforts to mitigate market price exposure, the estimated market price exposure for the non-trading portfolio associated with a 10% reduction in the average around-the-clock market price of electricity is an approximate $100 million decrease in net income. This sensitivity assumes an 80% hedge ratio and that price changes occur evenly throughout the year and across all markets. The sensitivity also assumes a static portfolio. We expect to actively manage our portfolio to mitigate the market price exposure. Actual results could differ depending on the specific timing of, and markets affected by, the price changes, as well as future changes in our portfolio.
Trading activities. We began to use financial contracts for trading purposes in the second quarter of 2001. The trading activities were entered into as a complement to our energy marketing portfolio and represent a very limited portion of our overall energy marketing activities. For example, the limit on open positions in electricity for any forward month represents less than 5% of the owned and contracted supply of electricity. The trading portfolio is planned to grow modestly in 2002, subject to stringent risk management limits and policies, including volume, stop-loss and value-at-risk limits to manage exposure to market risk. A value-at-risk (VAR) model is used to assess the market risk associated with financial derivative instruments entered into for trading purposes. VAR represents the potential gains or losses for instruments or portfolios due to changes in market factors, for a specified time period and confidence level. The measured VAR as of December 31, 2001, using a Monte Carlo model with a 95% confidence level and assuming a one-day time horizon was approximately $800,000. The measured VAR represents an estimate of the potential change in value of our portfolio of trading related financial derivative instruments. These estimates, however, are not necessarily indicative of actual results, which may differ due to the fact that actual market rate fluctuations may differ from forecasted fluctuations and due to the fact that the portfolio may change over the holding period.
Our energy contracts are accounted for under SFAS No. 133. Most non-trading contracts qualify for a normal purchases and normal sales exception under that accounting pronouncement and therefore are not recorded on the balance sheet and marked to market. Contracts that do not qualify for the
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exception are recorded as assets or liabilities on the balance sheet at fair value. Changes in the fair value of qualifying hedge contracts are recorded in Other Comprehensive Income, and gains and losses are recognized in earnings when the underlying transaction occurs. Changes in the fair value of derivative contracts that do not meet hedge criteria under SFAS No. 133 or the ineffective portion of hedge contracts is recognized in earnings on a current basis. Outlined below is a summary of the changes in fair value for those contracts included as assets and liabilities in our balance sheet for the year ended December 31, 2001:
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Non-trading |
Trading |
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(in millions) |
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| Fair value of contracts outstanding as of January 1, 2001 (Reflects the adoption of SFAS No. 133) | $ | (7 | ) | $ | — | |
| Change in fair value during 2001: | ||||||
| Contracts settled during year | 87 | 7 | ||||
| Mark-to-market unrealized gain (loss) | (2 | ) | 7 | |||
| Total change in Fair Value | 85 | 14 | ||||
Fair value of contracts outstanding at December 31, 2001 |
$ |
78 |
$ |
14 |
||
The total change in fair value during 2001 is reflected in the 2001 consolidated financial statements as follows:
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Non-trading |
Trading |
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|---|---|---|---|---|---|---|
| Mark-to-market gain on non-qualifying hedge contracts or hedge ineffectiveness reflected in earnings | $ | 16 | $ | 14 | ||
| Mark-to market hedge contracts reflected in Other Comprehensive Income | 69 | — | ||||
| Total change in fair value | $ | 85 | $ | 14 | ||
The majority of our contracts are non-exchange traded contracts valued using prices provided by external sources, which primarily represent price quotations available through brokers or over-the-counter, on-line exchanges. Prices reflect the average of the bid-ask midpoint prices obtained from all sources that we believe provide the most liquid market for the commodity. The terms for which such price information is available varies by commodity, by region and by product. The remainder of the assets represents contracts for which external valuations are not available, primarily option contracts. These contracts are valued using the Black model, an industry standard option valuation model and other valuation techniques. The fair values in each category reflect the level of forward prices and volatility factors as of December 31, 2001 and may change as a result of future
22
changes in these factors. The maturities of the net energy trading and non-trading assets and sources of fair value as of December 31, 2001 are as follows:
| |
Less than One Year |
One - Three Years |
Three - Five Years |
Total Fair Value |
||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| |
(in millions) |
|||||||||||||
| Non-trading: | ||||||||||||||
| Actively quoted prices | $ | — | $ | — | $ | — | $ | — | ||||||
| Prices provided by other external sources | 36 | 50 | — | 86 | ||||||||||
| Prices based on model or other valuation methods | (4 | ) | 2 | (6 | ) | (8 | ) | |||||||
| Total | $ | 32 | $ | 52 | $ | (6 | ) | $ | 78 | |||||
| Trading: | ||||||||||||||
| Actively quoted prices | $ | — | $ | — | $ | — | $ | — | ||||||
| Prices provided by other external sources | 10 | 4 | — | 14 | ||||||||||
| Prices based on model or other valuation methods | — | — | — | — | ||||||||||
| Total | $ | 10 | $ | 4 | $ | — | $ | 14 | ||||||
Management uses its best estimates to determine the fair value of commodity and derivative contracts it holds and sells. These estimates consider various factors, including closing exchange and over-the-counter price quotations, time value, volatility factors, and credit exposure. However, it is possible that future market prices could vary from those used in recording assets and liabilities from energy marketing and trading activities, and such variations could be material.
Credit Risk. We have credit risk associated with counterparty performance, which includes, but is not limited to, the risk of financial default or slow payment. Counterparty credit risk is managed through established policies, including establishing counterparty credit limits, and in some cases requiring deposits or letters of credit to be posted by certain counterparties. Our counterparty credit limits are based on a scoring model that considers a variety of factors, including leverage, liquidity, profitability, credit ratings and risk management capabilities. We have entered into master netting agreements with the majority of our large counterparties, which reduce exposure to risk by providing for the offset of amounts payable to the counterparty against the counterparty receivables.
We participate in the five established, real-time energy markets, which are administered by independent system operators (ISOs): Pennsylvania, New Jersey, Maryland, LLC (PJM), which is in the Mid-Atlantic Area Council region; New England and New York, which are both in the Northeast Power Coordinating Council region; California, which is in the Western Systems Coordinating Council region; and Texas, which is administered by the Electric Reliability Council of Texas. In 2001, approximately one-half of our transactions, on a megawatthour basis, were made in these markets. In these areas, power is traded through bilateral agreements between buyers and sellers and on the spot markets which are operated by the ISOs For sales into the spot markets administered by an ISO, the ISO maintains financial assurance policies that are established and enforced by those administrators. The credit policies of the ISOs may under certain circumstances require that losses arising from the default of one member on spot market transactions be shared by the remaining participants. Non-performance or non-payment by a major counterparty, could result in a material adverse impact on our financial condition, results of operations or net cash flows.
In areas where there is no spot market, electricity is purchased and sold solely through bilateral agreements.
Interest Rate Risk. We use a combination of fixed-rate and variable-rate debt to reduce interest rate exposure. Interest rate swaps may be used to adjust exposure when deemed appropriate based
23
upon market conditions. We also use forward-starting interest rate swaps and treasury rate locks to lock in interest rate levels in anticipation of future financings. These strategies are employed to maintain the lowest cost of capital. As of December 31, 2001, a hypothetical 10% increase in the interest rates associated with pollution control bonds would result in an approximately $1 million decrease in pre-tax earnings for 2002.
Equity Price Risk. We maintain trust funds, as required by the NRC, to fund certain costs of decommissioning our nuclear plants. As of December 31, 2001, these funds are reflected at fair value on our balance sheet. The mix of securities is designed to provide returns to be used to fund decommissioning and to compensate, including inflationary increases in decommissioning costs. However, the equity securities in the trusts are exposed to price fluctuations in equity markets, and the value of fixed rate, fixed income securities are exposed to changes in interest rates. We actively monitor the investment performance and periodically review asset allocation in accordance with our nuclear decommissioning trust fund investment guidelines. A hypothetical 10% increase in interest rates and decrease in equity prices would result in a $204 million reduction in the fair value of the trust assets.
Critical Accounting Policies
The preparation of financial statements in conformity with Generally Accepted Accounting Principles requires that management apply accounting policies and make estimates and assumptions that affect results of operations and the reported amounts of assets and liabilities in the financial statements. The following areas represent those that management believes are particularly important to the financial statements and that require the use of estimates and assumptions to describe matters that are inherently uncertain.
Accounting for Derivative Instruments. We use derivative financial instruments primarily to manage our commodity price and interest rate risks. Derivative financial instruments are accounted for under SFAS No. 133. Accounting for derivatives continues to evolve through guidance issued by the Derivatives Implementation Group (DIG) of the Financial Accounting Standards Board. To the extent that changes by the DIG modify current guidance, including the normal purchases and normal sales determination, the accounting treatment for derivatives may change.
Energy Contracts. To manage our use of generation supply (including owned and contracted assets), we enter into contracts to purchase or sell electricity, fossil fuels, and ancillary products such as transmission rights and congestion credits, and emission allowances. These energy marketing contracts are considered derivatives under SFAS 133 unless a determination is made that they qualify for a SFAS No. 133 normal purchases and normal sales exclusion. If the exclusion applies, those contracts are not marked-to-market and are not reflected in the financial statements until delivery occurs.
The availability of the normal purchases and normal sales exclusion to specific contracts is based on a determination that excess generation is available for a forward sale and similarly a determination that at certain times generation supply will be insufficient to serve load. This determination is based on internal models that forecast customer demand and generation supply. The models include assumptions regarding customer load growth rates, which are influenced by the economy, weather and the impact of customer choice, and generating unit availability, particularly nuclear generating unit capability factors. The critical assumptions used in the determination of normal purchases and normal sales are consistent with assumptions used in the general corporate planning process.
Energy contracts that are considered derivatives may be eligible for designation as hedges. If a contract is designated as a hedge, the change in its market value is generally deferred as a component of other comprehensive income until the transaction it is hedging occurs. Conversely, the change in the market value of derivatives not designated as hedges is recorded in current period earnings. To qualify as a cash flow hedge, the fair value changes in the derivative must be expected to offset 80%-120% of
24
the change in fair value or cash flows of the hedged item. The effectiveness of an energy contract designated as a hedge is determined by internal models that measure the statistical correlation between the derivative and the associated hedged item.
When external quoted market prices are not available, we use the Black model, a standard industry valuation model to determine the fair value of energy derivative contracts. The valuation model uses volatility assumptions relating to future energy prices based on specific energy markets and utilizes externally available forward market price curves.
Interest Rate Derivatives. We use derivatives to manage our exposure to fluctuation in interest rates and planned future debt issuances. Hedge accounting has been used for all interest rate derivatives to date based on the probability of the transaction and the expected highly effective nature of the hedging relationship between the interest rate swap contract and the interest payment or changes in fair value of the hedged debt. Dealer quotes are available for all of our interest rate swap agreement derivatives.
Nuclear Decommissioning. Our current estimate of our nuclear facilities' decommissioning cost is $7.2 billion in current year dollars. Calculating this estimate involves significant assumptions with respect to the expected increases in decommissioning costs relative to general inflation rates, changes in the regulatory environment or regulatory requirements, and the timing of decommissioning. The estimated service life of a nuclear station is also a significant assumption because decommissioning costs are generally recognized over the life of the generating station. Cost estimates for decommissioning our nuclear facilities have been prepared by an independent engineering firm and reflect currently existing regulatory requirements and available technology. Nuclear station service lives, over which the decommissioning costs are recognized, were extended by 20 years in 2001. The life extension is subject to NRC approval of an extension of existing NRC operating licenses, which generally are 40 years. As discussed in New Accounting Pronouncements, this accounting will be affected by the adoption of SFAS No. 143, "Asset Retirement Obligations" (SFAS No. 143) effective January 1, 2003.
Estimated Service Lives of Property, Plant and Equipment. We depreciate our generation facilities and other property plant and equipment over estimated useful service lives. These estimated useful service lives are determined using three criteria: (1) economic feasibility, (2) physical feasibility and (3) functional feasibility. Economic feasibility is demonstrated through a cost/benefit analysis that an asset is economically viable and that the asset is providing an overall financial benefit. Physical feasibility represents the fact that the actual plant and equipment can operate during the defined period. Changes in physical feasibility may result from changes in the regulatory environment or environmental restrictions. Functional feasibility evaluates the impact of technology changes on the estimated service lives. In addition, nuclear power stations operate under licenses granted by the NRC. Operating licenses for our operating plants are for 40 years. We have or intend to request 20-year life extensions of these operating licenses. If not extended, nuclear plant service lives would be limited by the expiration of licenses. During 2001, we increased the estimated service lives for our operating nuclear stations, certain fossil stations and our pumped storage station. As a result of the change in service lives, depreciation and decommissioning expense decreased $90 million ($54 million, net of income taxes). Annualized savings resulting from the change will be $132 million ($79 million, net of income taxes).
Outlook
Changes in the Utility Industry. The electric utility industry in the United States remains in transition. It is moving from a fully regulated industry, consisting primarily of integrated companies combining generation, transmission and distribution, to competitive wholesale generation markets with continuing regulation of transmission and distribution. The transition has resulted in substantial
25
disposition of generating assets by formerly integrated companies, the creation of separate and, in some cases, stand-alone generating companies and consolidation. During 2001, however, the pace of transition slowed. This slowdown was due primarily to public and governmental reactions to issues associated with deregulation efforts in California and the collapse of the wholesale electricity market in California.
At the Federal level, FERC remains committed to the development of wholesale generation markets. Although its proposal for the development of large regional transmission organizations to facilitate markets has been delayed, it is planning an initiative to standardize wholesale markets in the United States. At the state level, concerns raised by the California experiences have stalled new retail competition initiatives and slowed the separation of generation from regulated transmission and distribution assets.
We believe that the transition in the electric utility industry will continue, albeit at a slower pace than previously, particularly at the state level. This slower transition may be reflected in reduced industry consolidation in the near term and reduced disaggregation of regulated to unregulated services. These uncertainties may limit opportunities for us to pursue our plans to expand our generation portfolio.
We also believe that competition for electric generation services has created new risks and uncertainties in the industry. Some of these risks were clearly illustrated in California—the risks of inadequate sources of generation, having load obligations without owning generation, and price volatility. The situation in California also illustrated the need for additional infrastructure to support competitive markets. The uncertainties include future prices of generation services in both the wholesale and retail markets, supply and demand volatility, and changes in customer profiles that may impact margins on various electric service offerings. These uncertainties create additional risk for participants in the industry, including us, and may result in increased volatility in operating results from year to year.
Competitive Position. We compete nationally in the wholesale electric generation markets on the basis of price and service offerings, using our generation portfolio to assure customers of energy deliverability. We have agreed to supply ComEd and PECO with their load requirements for customers through 2006 and 2010, respectively. We have contracted with Exelon Energy, the competitive retail energy services subsidiary of Exelon, to meet its load requirements pursuant to its competitive retail generation sales agreements and, in addition, we have contracts to sell energy and capacity to third parties. To the extent that our resources exceed our contractual commitments, we market these resources on a short-term basis or sell them in the spot market.
Our supply agreements with ComEd and PECO are expected to provide us with a stable source of revenue; they do not, however, provide us with any guaranteed level of revenue. As long as we have commitments to ComEd and PECO, our revenues will largely be a function of the cost of fulfilling these obligations and how much electricity is available to sell in wholesale markets after fulfilling those contracts. Generally, to the extent market prices decrease, customers may have an incentive to obtain electricity from alternative energy suppliers. To the extent that customers choose alternative energy suppliers, our revenues from contracts with ComEd and PECO will be reduced and our revenues will depend more on prices in the wholesale markets. If market prices increase substantially and our load requirements exceed our generation capacity, we may be required to purchase expensive power in the wholesale markets. Thus, any dramatic change in electricity prices combined with switching by ComEd's and PECO's customers could have an adverse effect on our results of operations or financial condition. Further, while our contracts with ComEd and PECO are currently a substantial portion of our business, we cannot predict whether they will be renewed at the end of their respective terms or, if renewed, what the terms of such renewal would be.
26
Our future results of operations also depend upon our ability to operate our generating facilities efficiently to meet our contractual commitments and to sell energy services in the wholesale markets. A substantial portion of our generating capacity, including all of the nuclear capacity, is base-load generation designed to operate for extended periods of time at low variable costs. Nuclear generation is currently the most cost-effective way for us to meet our commitments for sales to affiliated entities and other utilities. During 2001, our nuclear generating fleet, including AmerGen, operated at a 94.4% weighted average capacity factor. The number of refueling outages, including AmerGen, is expected to increase to eleven in 2002 from six in 2001 and, accordingly, our planned nuclear capacity factor for 2002 is 91%. Failure to achieve these capacity levels may require us to contract or purchase more expensive energy in the spot market to meet these commitments. Maintenance and capital expenditures during nuclear refueling outages are expected to increase by $80 million and $24 million, respectively, in 2002 compared to 2001 as a result of the additional nuclear refueling outages. Because of our reliance on nuclear facilities, any changes in regulations by the NRC requiring additional investments or resulting in increased operating or decommissioning costs of nuclear generating units could adversely affect our results of operations.
After we have met our contractual commitments, we sell energy in the wholesale markets. These sales expose us to the risks of rising and falling prices in those markets, and cash flows may vary accordingly. After our contracts with ComEd and PECO expire, our cash flows will largely be determined by our ability to successfully market energy, capacity and ancillary services and by wholesale prices of electricity.
We currently intend to grow our generation portfolio through investments, acquisitions and the development of new energy projects, the completion of any of which is subject to substantial risk. The competitive energy market is still evolving following deregulation and we may not be successful in anticipating appropriate market opportunities. It is possible that, due to a variety of factors, including purchase price, operating performance and future market conditions, we would be unable to achieve our goals.
Our wholesale marketing division, Power Team, uses our generation portfolio, transmission rights and expertise to ensure delivery of generation to wholesale customers under long-term and short-term contracts. Power Team is responsible for supplying the load requirements of ComEd and PECO and markets the remaining energy in the wholesale markets. Power Team also buys and sells power in the wholesale markets. Trading activities were initiated in 2001 and represent a small portion of Power Team's activity. As of December 31, 2001, trading activities accounted for less than 1% of our EBIT. Trading activities are expected to increase modestly in 2002; trading activity growth will be dependent on the continued development of the wholesale energy markets and Power Team's ability to manage trading and credit risks in those markets. The spot markets also involve the credit risks of market participants purchasing energy, which we may not be able to manage or hedge. We use financial trading primarily to complement the marketing of our generation portfolio. We intend to manage the risk of these activities through a mix of long-term and short-term supply obligations and through the use of established policies, procedures and trading limits. Financial trading, together with the effects of SFAS No. 133, may cause volatility in our future results of operations.
Other Factors
Environmental. Our operations have in the past and may in the future require substantial capital expenditures in order to comply with environmental laws. Additionally, under Federal and state environmental laws, we are generally liable for the costs of remediating environmental contamination of property now owned by us or formerly owned by ComEd or PECO and of property contaminated by hazardous substances generated by us, ComEd or PECO.
27
As of December 31, 2001 and 2000, we had accrued $14 million and $16 million, respectively, for environmental investigation and remediation costs, other than decommissioning. We expect to spend $5 million for environmental remediation activities in 2002. We cannot predict whether we will incur other significant liabilities for any additional investigation and remediation costs at these or additional sites identified by us, environmental agencies or others, or whether such costs will be recoverable from third parties.
Security Issues and Other Impacts of Terrorist Actions. The events of September 11, 2001 have affected our operating procedures and costs and are expected to affect the cost and availability of the insurance coverages that we carry. The NRC has issued Safeguards and Threat Advisories to all nuclear power plant licensees, including us, requesting that they place their facilities on highest alert security status. In response to the NRC Advisories and on our own initiative, we also implemented enhanced security measures, such as increased guard forces, the erection of additional physical barriers, and heightened communication with authorities at all levels of government. In addition to the Advisories, the NRC began an initiative to perform a "top to bottom" review of its safeguards and security programs and requirements in light of the events of September 11.
On February 25, 2002, the NRC issued immediately effective orders modifying the operating licenses for all nuclear power plants to require all licensees, including us, to implement certain interim security enhancements. The security requirements imposed by the NRC's orders issued to us are currently estimated to increase capital expenditures by approximately $1 million per station for improvements, such as enhanced vehicle barriers, modifications to plant facilities and increased size of guard forces.
Insurance. We carry nuclear liability insurance. The Price-Anderson Act limits the liability of nuclear reactor owners for claims arising from a single incident. The current limit is $9.5 billion and is subject to change to account for the effects of inflation and changes in the number of licensed reactors. We carry the maximum available commercial insurance of $200 million. The remaining $9.3 billion is provided through mandatory participation in a financial protection pool. Price-Anderson is scheduled to expire on August 1, 2002. While there are numerous bills proposing to review Price-Anderson, we cannot predict at this time whether Congress will renew it or the effects on operations resulting from the expiration of the Price-Anderson Act.
In addition to nuclear liability insurance, we carry property damage and liability insurance for our properties and operations. Our property insurance through Nuclear Electric Insurance Limited (NEIL) provides coverage for damages caused by acts of terrorism at any of our nuclear generating stations. The terrorism endorsement to the NEIL policy specifies that the coverage applies to acts of terrorism similar to the September 11, 2001 events. In the event that one or more acts of terrorism cause accidental property damage within a 12-month period from the first accidental property damage under one or more policies for all insureds, the maximum recovery for all losses by all insureds will be an aggregate of $3.24 billion plus such additional amounts as the insurer may recover for all such losses from reinsurance, indemnity or any other source applicable to such losses. If total property losses exceed available funds under the policy, proportionate recovery is provided to cover a portion of an insured's property losses. The percentage recovery would be equal to the ratio of the insured's property losses and the total of all property losses.
NEIL also provides replacement power cost insurance in the event of a major accidental outage at a nuclear station. The policy provides for a waiting period before recovery of costs can commence. The premium for this coverage is subject to assessment for adverse loss experience, with a maximum assessment of $46 million per year. Recovery under this insurance for terrorist acts is subject to the $3.24 billion aggregate limit and is secondary to the property insurance described above.
We are self-insured to the extent that any losses may exceed the amount of insurance maintained. NEIL provides property and business interruption insurance for our nuclear operations. In recent years,
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NEIL has made distributions to its members. Our distribution for 2001 was $69 million, which was recorded as a reduction to Operating and Maintenance Expense on our Statements of Income. Due in part to the September 11, 2001 events, we cannot predict the level of future distributions, although they are expected to be lower than historical levels.
In addition, we participate in the American Nuclear Insurers Master Worker Program, which provides coverage for worker tort claims filed for bodily injury caused by a nuclear energy accident. This program was modified, effective January 1, 1998, to provide coverage to all workers whose nuclear-related employment began on or after the commencement date of reactor operations. We will not be liable for a retrospective assessment under this new policy. However, in the event losses incurred under the small number of policies in the old program exceed accumulated reserves, a maximum retrospective assessment of up to $50 million could apply.
We do not carry any business interruption insurance other than NEIL coverage for nuclear operations. We cannot at this time predict the effect on our operations of any changes in any of these insurance policies because of terrorist acts or otherwise.
Benefit Plans. We maintain defined benefit pension plans and post-retirement welfare benefit plans. All of our employees are eligible to participate in these plans. Management employees and electing union employees, hired on or after January 1, 2001, are eligible to participate in newly established Exelon cash balance pension plans. Management employees who were active participants in the former ComEd and PECO pension plans on December 31, 2000 and remain employed by Exelon or a participating subsidiary on January 1, 2002, have the opportunity to continue to participate in the pension plan or to transfer to the cash balance plan. Participants in the cash balance plan, unlike participants in the other defined benefit plans, may request a lump-sum cash payment upon the termination of their employment, which may result in increased cash requirements from pension plan assets. We may be required to increase future funding to the pension plan as a result of these increased cash requirements.
Due to the performance of the United States debt and equity markets in 2001, the value of assets held in trusts to satisfy the obligations of pension and postretirement benefit plans has decreased. Also, as a result of the merger and corporate restructuring, there was a larger number of employees taking advantage of retirement benefits in 2001 than in other years. These factors may also result in additional future funding requirements of the pension and postretirement benefit plans.
New Accounting Pronouncements
In 2001, the Financial Accounting Standards Board (FASB) issued SFAS No. 141, "Business Combinations" (SFAS No. 141), SFAS No. 142 "Goodwill and Other Intangible Assets" (SFAS No. 142, SFAS No. 143, and SFAS No. 144 "Accounting for the Impairment or Disposal of Long-Lived Assets" (SFAS No. 144).
SFAS No. 141 requires that all business combinations be accounted for under the purchase method of accounting and establishes criteria for the separate recognition of intangible assets acquired in business combinations. SFAS No. 141 is effective for business combinations initiated after June 30, 2001. In addition, SFAS No. 141 requires that unamortized negative goodwill related to pre-July 1, 2001 purchase be recognized as change in accounting principle concurrent with the adoption of SFAS No. 142. Included on AmerGen's balance sheet is $43 million of negative goodwill, net of accumulated amortization. Upon AmerGen's adoption of SFAS No. 141 on January 1, 2002, we will recognize our appropriate share of approximately $22 million in additional income as a cumulative effect of a change in accounting principle.
SFAS No. 142 establishes new accounting and reporting standards for goodwill and intangible assets. We adopted SFAS No. 142 as of January 1, 2002. Under SFAS No. 142, effective January 1,
29
2002, goodwill is no longer subject to amortization. After January 1, 2002, goodwill will be subject to an assessment for impairment using a two-step fair value based test, the first step of which must be performed at least annually, or more frequently if events or circumstances indicate that goodwill might be impaired. The first step compares the fair value of a reporting unit to its carrying amount, including goodwill. If the carrying amount of the reporting unit exceeds its fair value, the second step is performed. The second step compares the carrying amount of the goodwill to the fair value of the goodwill. If the fair value of goodwill is less than the carrying amount, an impairment loss would be reported as a reduction to goodwill and a charge to operating expense, except at the transition date, when the loss would be reflected as a cumulative effect of a change in accounting principle. As of December 31, 2001, we did not have any goodwill recorded on our Consolidated Balance sheets. Accordingly, we do not expect the adoption of SFAS No. 142 to have a material impact on our financial statements.
SFAS No. 143 provides accounting requirements for retirement obligations associated with tangible long-lived assets. We expect to adopt SFAS No. 143 on January 1, 2003. Retirement obligations associated with long-lived assets included within the scope of SFAS No. 143 are those for which there is a legal obligation to settle under existing or enacted law, statute, written or oral contract or by legal construction under the doctrine of promissory estoppel. Adoption of SFAS No. 143 will change the accounting for the decommissioning of our nuclear generating plants. Currently, we record the obligation for decommissioning ratably over the lives of the plants. The January 1, 2003 adoption of this standard will require a cumulative effect adjustment effective the date of adoption to adjust plant assets and decommissioning liabilities to the values they would have been had SFAS No. 143 been employed from the in-service dates of the plants.
The effect of this cumulative adjustment will be to increase the decommissioning liability to reflect a full decommissioning obligation in current year dollars. Additionally, SFAS No. 143 will require the accrual of an asset related to the full amount of the decommissioning obligation, which will be amortized over the remaining lives of the plants. The difference between the asset recognized and the liability recorded upon adoption of the standard will be charged to earnings and recognized as a cumulative effect, net of expected regulatory recovery. The decommissioning liability to be recorded represents an obligation for the future decommissioning of the plants, and as a result, interest expense will be accrued on this liability until such time as the obligation is satisfied.
We are in the process of evaluating the impact of SFAS No. 143 on our financial statements, and cannot determine the ultimate impact of adoption at this time; however, the cumulative effect could be material to our earnings. Additionally, although over the life of the plant the charges to earnings for the depreciation of the asset and the interest on the liability will be equal to the amounts currently recognized as decommissioning expense, the timing of those charges will change and in the near-term period subsequent to adoption, the depreciation of the asset and the interest on the liability could result in an increase in expense.
SFAS No. 144 establishes accounting and reporting standards for both the impairment and disposal of long-lived assets. This statement is effective for fiscal years beginning after December 15, 2001 and provisions of this statement are generally applied prospectively. We are in the process of evaluating the impact of SFAS No. 144 on our financial statements, and we do not expect the impact to be material.
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| |
Page(s) |
||
|---|---|---|---|
| Report of Independent Accountants | F-2 | ||
| Consolidated Financial Statements: | |||
| Statements of Income | F-3 | ||
| Statements of Cash Flows | F-4 | ||
| Balance Sheets | F-5 | ||
| Statements of Changes in Divisional/Member's Equity | F-6 | ||
| Statements of Other Comprehensive Income | F-7 | ||
| Notes to Consolidated Financial Statements | F-8 - 39 | ||
F-1
REPORT OF INDEPENDENT ACCOUNTANTS
To the Member and Board of Directorse
of Exelon Generation Company LLC
In our opinion, the accompanying consolidated balance sheets and related consolidated statements of income, cash flows, changes in divisional/member's equity and comprehensive income present fairly, in all material respects, the financial position of Exelon Generation Company, LLC and Subsidiary Companies (Exelon Generation) at December 31, 2001 and December 31, 2000, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2001 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of Exelon Generation's management; our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which 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 examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
As discussed in Note 3 to the consolidated financial statements, Exelon Generation's parent company, Exelon Corporation, acquired Unicom Corporation on October 20, 2000 in a business combination accounted for under the purchase method of accounting. The results of the acquired generation-related business are included in the consolidated financial statements of Exelon Generation since the acquisition date.
As discussed in Note 1, Exelon Generation changed its method of accounting for derivative instruments and hedging activities effective January 1, 2001.
/s/ PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
March 1,
2002
Philadelphia, PA
F-2
EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF INCOME
(Dollars in Millions)
| |
For the Years Ended December 31, |
|||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|
| |
2001 |
2000 |
1999 |
|||||||||
| Operating revenues: | ||||||||||||
| Operating revenues | $ | 2,946 | $ | 1,723 | $ | 1,584 | ||||||
| Operating revenues—affiliates | 4,102 | 1,551 | 841 | |||||||||
| Total operating revenues | 7,048 | 3,274 | 2,425 | |||||||||
| Operating expenses: | ||||||||||||
| Fuel and purchased power | 4,093 | 1,845 | 1,205 | |||||||||
| Purchased power—affiliates | 125 | 1 | — | |||||||||
| Operating and maintenance | 1,338 | 754 | 658 | |||||||||
| Operating and maintenance—affiliates | 189 | 46 | 100 | |||||||||
| Depreciation and decommissioning | 282 | 123 | 125 | |||||||||
| Taxes other than income | 149 | 64 | 37 | |||||||||
| Total operating expenses | 6,176 | 2,833 | 2,125 | |||||||||
| Operating income | 872 | 441 | 300 | |||||||||
| Other income and deductions: | ||||||||||||
| Interest expense | (115 | ) | (41 | ) | (12 | ) | ||||||
| Equity in earnings of unconsolidated affiliates | 90 | 4 | — | |||||||||
| Other, net | (8 | ) | 16 | 41 | ||||||||
| Total other income and deductions | (33 | ) | (21 | ) | 29 | |||||||
| Income before income taxes and cumulative effect of a change in accounting principle | 839 | 420 | 329 | |||||||||
| Income taxes | 327 | 160 | 125 | |||||||||
| Income before cumulative effect of a change in accounting principle | 512 | 260 | 204 | |||||||||
| Cumulative effect of a change in accounting principle (net of income taxes of $7) | 12 | — | — | |||||||||
| Net income | $ | 524 | $ | 260 | $ | 204 | ||||||
F-3
EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in Millions)
| |
For the Years Ended December 31, |
||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| |
2001 |
2000 |
1999 |
||||||||||
| Cash flows from operating activities: | |||||||||||||
| Net income | $ | 524 | $ | 260 | $ | 204 | |||||||
| Adjustments to reconcile net income to net cash flows provided by operating activities: | |||||||||||||
| Depreciation and decommissioning (including amortization of nuclear fuel) | 674 | 289 | 270 | ||||||||||
| Provision for uncollectible accounts | 15 | 2 | — | ||||||||||
| Allowance for obsolete inventory | 11 | 1 | — | ||||||||||
| Cumulative effect of a change in accounting principle (net of income taxes) | (12 | ) | — | — | |||||||||
| Deferred income taxes | 33 | (47 | ) | 23 | |||||||||
| Amortization of investment tax credit | (8 | ) | (13 | ) | (12 | ) | |||||||
| Earnings from equity investments | (90 | ) | (4 | ) | — | ||||||||
| Net realized losses on decommissioning trust funds | 127 | — | — | ||||||||||
| Unrealized gains on derivative financial instruments | (30 | ) | — | — | |||||||||
| Interest expense on spent nuclear fuel obligation | 33 | 10 | — | ||||||||||
| Expense in contributions to long term incentive plan | — | 44 | — | ||||||||||
| Other operating activities | (6 | ) | (4 | ) | 22 | ||||||||
Changes in working capital: |
|||||||||||||
| Accounts receivable | 127 | (158 | ) | (54 | ) | ||||||||
| Accounts receivable from affiliates | 104 | (342 | ) | (66 | ) | ||||||||
| Accounts payable to affiliates | (99 | ) | 99 | — | |||||||||
| Inventories | (22 | ) | (58 | ) | (5 | ) | |||||||
| Accounts payable | (101 | ) | 91 | (70 | ) | ||||||||
| Accrued expenses | 61 | 286 | 114 | ||||||||||
| Other current assets | 2 | 37 | (7 | ) | |||||||||
| Other current liabilities | (12 | ) | (17 | ) | 10 | ||||||||
| Net cash provided by operating activities | 1,331 | 476 | 429 | ||||||||||
| Cash flows from investing activities: | |||||||||||||
| Investment in nuclear fuel | (336 | ) | (112 | ) | (95 | ) | |||||||
| Investment in plant | (515 | ) | (214 | ) | (253 | ) | |||||||
| Investment in AmerGen Energy, LLC | — | — | (39 | ) | |||||||||
| Investment in Sithe Energies, Inc. | — | (704 | ) | — | |||||||||
| Change in long-term receivable, affiliate | 72 | 1 | — | ||||||||||
| Proceeds from nuclear decommissioning trust funds | 1,624 | 265 | 69 | ||||||||||
| Investment in nuclear decommissioning trust funds | (1,863 | ) | (380 | ) | (95 | ) | |||||||
| Other investment activity | (92 | ) | (20 | ) | (18 | ) | |||||||
| Net cash used in investing activities | (1,110 | ) | (1,164 | ) | (431 | ) | |||||||
| Cash flows from financing activities: | |||||||||||||
| Change in note payable, member | (696 | ) | 696 | — | |||||||||
| Issuance of long-term debt, net of issuance costs | 820 | — | 6 | ||||||||||
| Retirement of long-term debt | (4 | ) | (4 | ) | (4 | ) | |||||||
| Distributions to member | (121 | ) | — | — | |||||||||
| Net cash (used in) provided by financing activities | (1 | ) | 692 | 2 | |||||||||
| Increase in cash and cash equivalents | 220 | 4 | — | ||||||||||
| Cash and cash equivalents at beginning of period | 4 | — | — | ||||||||||
| Cash and cash equivalents at end of period | $ | 224 | $ | 4 | $ | — | |||||||
F-4
EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Dollars in Millions)
| |
December 31, |
||||||||
|---|---|---|---|---|---|---|---|---|---|
| |
2001 |
2000 |
|||||||
| Assets | |||||||||
| Current assets: | |||||||||
| Cash and cash equivalents | $ | 224 | $ | 4 | |||||
| Accounts receivable, net | |||||||||
| Customer | 316 | 316 | |||||||
| Other | 165 | 198 | |||||||
| Affiliates | 327 | 941 | |||||||
| Inventories, net, at average cost: | |||||||||
| Fossil fuel | 105 | 93 | |||||||
| Materials and supplies | 202 | 203 | |||||||
| Other | 65 | 38 | |||||||
| Total current assets | 1,404 | 1,793 | |||||||
Property, plant and equipment, net |
1,160 |
831 |
|||||||
| Nuclear fuel, net | 843 | 896 | |||||||
Deferred debits and other assets: |
|||||||||
| Deferred income taxes, net | 297 | 337 | |||||||
| Nuclear decommissioning trust funds | 3,165 | 3,127 | |||||||
| Investments | 859 | 762 | |||||||
| Receivables from affiliate | 291 | 363 | |||||||
| Other | 223 | 153 | |||||||
| Total deferred debits and other assets | 4,835 | 4,742 | |||||||
| Total assets | $ | 8,242 | $ | 8,262 | |||||
| Liabilities and Divisional/Member's Equity | |||||||||
| Current liabilities: | |||||||||
| Note payable to parent | $ | — | $ | 696 | |||||
| Payable to affiliate | — | 99 | |||||||
| Long-term debt due within one year | 4 | 4 | |||||||
| Accounts payable | 588 | 618 | |||||||
| Accrued expenses | 303 | 576 | |||||||
| Deferred income taxes | 7 | — | |||||||
| Other | 171 | 183 | |||||||
| Total current liabilities | 1,073 | 2,176 | |||||||
Long-term debt |
1,021 |
205 |
|||||||
Deferred credits and other liabilities: |
|||||||||
| Unamortized investment tax credits | 234 | 242 | |||||||
| Nuclear decommissioning liability for retired plants | 1,353 | 1,301 | |||||||
| Pension obligations | 118 | 172 | |||||||
| Non-pension postretirement benefits obligation | 384 | 377 | |||||||
| Spent nuclear fuel obligation | 843 | 810 | |||||||
| Other | 280 | 369 | |||||||
| Total deferred credits and other liabilities | 3,212 | 3,271 | |||||||
| Commitments and contingencies (See Note 11) | — | — | |||||||
Divisional equity |
— |
2,610 |
|||||||
| Member's equity: | |||||||||
| Membership interest | 2,315 | ||||||||
| Undistributed earnings | 524 | ||||||||
| Accumulated other comprehensive income | 97 | — | |||||||
| Total divisional/member's equity | 2,936 | 2,610 | |||||||
| Total liabilities and divisional/member's equity | $ | 8,242 | $ | 8,262 | |||||
The accompanying notes are an integral part of these consolidated financial statements.
F-5
EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CHANGES IN DIVISIONAL/MEMBER'S EQUITY
(Dollars in Millions)
| |
Divisional Equity |
Membership Interest |
Undistributed Earnings |
Accumulated Other Comprehensive Income |
Total Divisional/ Member's Equity |
||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Balance, January 1, 1999 | $ | 746 | $ | — | $ | — | $ | — | $ | 746 | |||||||
| Net income | 204 | 204 | |||||||||||||||
| Balance, December 31, 1999 | 950 | 950 | |||||||||||||||
| Net income | 260 | 260 | |||||||||||||||
| Contribution of net assets as a result of merger with Unicom | 1,400 | 1,400 | |||||||||||||||
| Balance, December 31, 2000 | 2,610 | 2,610 | |||||||||||||||
| Formation of LLC | (2,610 | ) | 2,610 | — | |||||||||||||
| Non-cash distribution to member | (174 | ) | (174 | ) | |||||||||||||
| Net income | 524 | 524 | |||||||||||||||
| Distribution to member | (121 | ) | (121 | ) | |||||||||||||
| Reclassified net unrealized losses on marketable securities, net of income taxes of $22 | (23 | ) | (23 | ) | |||||||||||||
| Comprehensive income, net of income tax benefit of $171 | 120 | 120 | |||||||||||||||
| Balance, December 31, 2001 | $ | — | $ | 2,315 | $ | 524 | $ | 97 | $ | 2,936 | |||||||
The accompanying notes are an integral part of these consolidated financial statements.
F-6
EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Dollars in Millions)
| |
For the Years Ended December 31 |
|||||||||
|---|---|---|---|---|---|---|---|---|---|---|
| |
2001 |
2000 |
1999 |
|||||||
| Net income | $ | 524 | $ | 260 | $ | 204 | ||||
| Other comprehensive income: | ||||||||||
| SFAS 133 transitional adjustment, net of income taxes of $3 | 5 | |||||||||
| Net unrealized gains on nuclear decommissioning trust funds, net of income taxes of $138 | 69 | |||||||||
| Cash flow hedge fair value adjustment, net of income taxes of $29 | 48 | |||||||||
| Realized loss on forward starting interest rate swap net of income taxes of $1 | (2 | ) | ||||||||
| Total other comprehensive income | 120 | — | — | |||||||
| Total comprehensive income | $ | 644 | $ | 260 | $ | 204 | ||||
The accompanying notes are an integral part of these consolidated financial statements.
F-7
EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in Millions, unless
otherwise noted)
1. Summary of Significant Accounting Policies
Description of Business
Exelon Generation Company, LLC (Exelon Generation) is a limited liability company engaged principally in the production and wholesale marketing of electricity in various regions of the United States. In 2001, the Company also began trading activities. Exelon Generation is wholly owned by Exelon Corporation (Exelon). In connection with the restructuring by Exelon to separate the regulated energy delivery business of its subsidiaries Commonwealth Edison Company (ComEd) and PECO Energy Company (PECO) from its unregulated businesses, including its generation business, Exelon Generation began operations as a separate indirect subsidiary of Exelon effective January 1, 2001. Exelon Generation has numerous wholly owned subsidiaries. These subsidiaries were primarily established to hold certain hydro electric and peaking unit facilities as well as the 49.9% interest in Sithe Energies, Inc. (Sithe) and 20.99% investment in Keystone Fuels, LLC. In addition, Exelon Generation also has a finance company subsidiary, Exelon Generation Finance Company, LLC, which provides certain financing for Exelon Generation's other subsidiaries. Exelon Generation also owns a 50% investment in AmerGen Energy Company, LLC (AmerGen).
Basis of Presentation
The consolidated financial statements include the accounts of all majority-owned subsidiaries of Exelon Generation after the elimination of intercompany accounts and transactions. Exelon Generation consolidates its proportionate interest in jointly owned electric utility plants. Exelon Generation accounts for its investments in 20% to 50% owned entities under the equity method of accounting.
The consolidated financial statements of Exelon Generation as of December 31, 2000 and for the years ended December 31, 2000 and 1999 present the financial position, results of operations and net cash flows of the generation-related business of Exelon prior to its corporate restructuring on January 1, 2001. Exelon Generation operated as a separate business subsequent to electric-industry restructuring in Pennsylvania effective January 1, 1999. Prior to that date, Exelon (and its predecessor, PECO Energy Company) operated as a fully integrated electric and gas utility, and revenues and expenses were not separately identified in the accounting records. The consolidated financial statements are not necessarily indicative of the financial position, results of operations or net cash flows that would have resulted had the generation-related business been a separate entity during the periods presented. For periods prior to the restructuring, references to Exelon Generation mean the generation-related business of Exelon Corporation.
Certain information in these consolidated financial statements relating to the results of operations and financial condition of Exelon Generation for periods prior to Exelon's restructuring was derived from the historical financial statements of Exelon. Various allocation methodologies were employed to separate the results of operations and financial condition of the generation-related portion of Exelon's business from the historical financial statements for the periods presented prior to the restructuring. Revenues include the generation component of revenue from Exelon's operations and any generation-related revenues, such as ancillary services and wholesale energy activity. Expenses including fuel and other energy-related costs, including purchased power, operations and maintenance and depreciation and amortization, as well as assets, such as property, plant and equipment, materials and supplies and fuel, were specifically identified for Exelon Generation's operations. Various allocations were used to
F-8
disaggregate other common expenses, assets and liabilities between Exelon Generation and Exelon's other businesses, primarily the regulated transmission and distribution operations.
Management believes that these allocation methodologies are reasonable; however, had Exelon Generation existed as a separate company prior to January 1, 2001, its results could have significantly differed from those presented herein. In addition, future results of operations, financial position and net cash flows could materially differ from the historical results presented.
Segment Information
Exelon Generation operates in one business comprising its generation and marketing of energy and energy-related products in the United States.
Use of Estimates
The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of 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. Significant estimates have been made in the accounting for derivatives, nuclear decommissioning liabilities and estimated service lives for plant.
Revenue Recognition
Operating revenues are generally recorded as service is rendered or energy is delivered to customers. At the end of each month, Exelon Generation accrues an estimate for unbilled energy provided to its customers. Premiums received and paid on option contracts and swap arrangements are amortized to revenue and expense over the life of the contracts. Certain of these contracts are considered derivative instruments and are recorded at fair value with subsequent changes in fair value recognized as revenues and expenses unless hedge accounting is applied.
Commodity derivatives used for trading purposes are accounted for using the mark-to-market method. Under this methodology, these derivatives are adjusted to fair value, and the unrealized gains and losses are recognized in current period income.
Nuclear Fuel
The cost of nuclear fuel is capitalized and charged to fuel expense using the units of production method. Estimated costs of nuclear fuel storage and disposal at operating plants are charged to expense as the related fuel is consumed.
Emission Allowances
Emission allowances are included in deferred debits and other assets and are carried at acquisition cost and charged to fuel expense as they are used in operations. Allowances held can be used from years 2002 to 2028.
F-9
Depreciation and Decommissioning
Depreciation is provided over the estimated useful service lives of the property, plant and equipment on a straight-line basis. Nuclear power stations operate under licenses granted by the Nuclear Regulatory Commission (NRC.) Operating licenses for Exelon Generation's operating plants are for 40 years. Exelon Generation has or intends to request 20 year extensions of these operating licenses. If not extended, nuclear plant service lives would be limited by the expiration of the licenses.
The average estimated useful service lives currently being applied to determine depreciation and decommissioning expense of property, plant and equipment by type of asset are as follows:
| Nuclear | 60 years | |
| Fossil | 40 years | |
| Hydro | 100 years | |
| Other | 5-50 years |
Exelon Generation's current estimate of the costs for decommissioning its ownership share of its nuclear generation stations is charged to operations over the expected service life of the plant. Exelon Generation's affiliates PECO and ComEd are currently recovering costs for the decommissioning of nuclear generating stations through regulated customer rates. Amounts collected for decommissioning by Exelon Generation's affiliates are remitted to Exelon Generation and are deposited in trust accounts and invested for the funding of future decommissioning costs. Exelon Generation accounts for the current period's cost of decommissioning related to generation plants previously owned by PECO by recording a charge to depreciation and decommissioning expense and a corresponding liability in accumulated depreciation concurrently with decommissioning collections.
For Exelon Generation's active nuclear generating stations previously owned by ComEd, annual decommissioning expense is based on an annual assessment of the difference between the current cost of decommissioning estimate and the decommissioning liability recorded in accumulated depreciation. The difference is amortized to depreciation and decommissioning expense on a straight-line basis over the remaining lives of the operating plants with the corresponding offset to accumulated depreciation. The current decommissioning cost estimate (adjusted annually to reflect inflation), for the former ComEd retired units recorded in deferred credits and other liabilities is accreted to depreciation and decommissioning expense. Exelon Generation believes that the amounts being recovered by ComEd and PECO from their customers through electric rates along with the earnings on the trust funds will be sufficient to fully fund its decommissioning obligations.
Research and Development
Research and development costs are charged to expense as incurred.
Capitalized Interest
Exelon Generation capitalizes the costs during construction of debt funds used to finance its construction projects. Exelon Generation recorded capitalized interest of $17 million, $2 million and $6 million in 2001, 2000 and 1999, respectively.
F-10
Income Taxes
As part of Exelon's consolidated group, Exelon Generation files a consolidated Federal income tax return with Exelon. Income taxes are allocated to each of Exelon subsidiaries within the consolidated group, including Exelon Generation, based on the separate return method.
Deferred Federal and state income taxes are provided on all temporary differences between book bases and tax bases of assets and liabilities. Investment tax credits previously used for income tax purposes have been deferred on Exelon Generation's consolidated balance sheet and are recognized in income over the life of the related property.
Cash and Cash Equivalents
Exelon Generation considers all temporary cash investments purchased with an original maturity of three months or less to be cash equivalents.
Marketable Securities
Marketable securities are classified as available-for-sale securities and are reported at fair value, with the unrealized gains and losses, net of tax, reported in other comprehensive income. The cost of these securities is determined on the basis of specific identification. At December 31, 2001 and 2000, Exelon Generation had no held-to-maturity or trading securities.
Unrealized gains and losses on marketable securities held in the nuclear decommissioning trust funds associated with the former PECO plants are reported in accumulated depreciation. Unrealized gains and losses on marketable securities held in the nuclear decommissioning trust funds associated with the former ComEd plants are reported in accumulated other comprehensive income.
Inventories
Inventories, which consist primarily of fuel and materials and supplies, are valued at the lower of cost or market and are stated on the average cost method.
Property, Plant and Equipment
Property, plant and equipment is recorded at cost. Exelon Generation evaluates the carrying value of property, plant and equipment and other long-term assets based upon current and anticipated undiscounted cash flows, and recognizes an impairment when it is probable that such estimated cash flows will be less than the carrying value of the asset. Measurement of the amount of impairment, if any, is based upon the difference between carrying value and fair value. The cost of maintenance, repairs and minor replacements of property are charged to maintenance expense as incurred. The cost and accumulated depreciation of property, plant and equipment retired or otherwise disposed of are removed from the related accounts and included in the determination of the gain or loss on disposition.
Comprehensive Income
Comprehensive income includes all changes in equity during a period except those resulting from investments by and distributions to the member. Comprehensive income primarily relates to unrealized
F-11
gains or losses on securities held in nuclear decommissioning trust funds and unrealized gains and losses on cash flow hedge instruments.
Derivative Financial Instruments
Subsequent to January 1, 2001, Exelon Generation accounts for derivative financial instruments under SFAS No. 133 "Accounting for Derivatives and Hedging Activities" (SFAS No. 133). Under the provisions of SFAS No. 133, all derivatives are recognized on the balance sheet at their fair value unless they qualify for a normal purchases or normal sales exception. Derivative financial instruments are recorded as other assets and liabilities in the consolidated balance sheet and classified as current or non-current based on the maturity date. Changes in the fair value of the derivative financial instruments are recognized in earnings unless specific hedge accounting criteria are met. A derivative financial instrument can be designated as a hedge of the fair value of a recognized asset or liability or of an unrecognized firm commitment (fair value hedge), or a hedge of a forecasted transaction or the variability of cash flows to be received or paid related to a recognized asset or liability (cash flow hedge).
Changes in the fair value of a derivative that is highly effective as, and is designated and qualifies as, a fair value hedge, along with the gain or loss on the hedged asset or liability that is attributable to the hedged risk, are recorded in earnings. Changes in the fair value of a derivative that is highly effective as, and is designated as and qualifies as a cash flow hedge are recorded in other comprehensive income, until earnings are affected by the variability of cash flows being hedged.
Pursuant to Exelon's Risk Management Policy (RMP), Exelon Generation uses derivatives to manage the utilization of its available generating capability and provisions of wholesale energy to its affiliates. Exelon Generation also utilizes energy option contracts and energy financial swap arrangements to limit the market price risk associated with forward energy commodity contracts. Exelon Generation enters into certain energy related derivatives for trading or speculative purposes. Exelon Generation may also enter into derivatives to manage its exposure to fluctuation in interest rates related to its variable rate debt instruments, changes in interest rates related to planned future debt issuances prior to their actual issuance and changes in the fair value of outstanding debt which is planned for early retirement. As part of Exelon Generation's energy marketing business, Exelon Generation enters into contracts to buy and sell energy to meet the requirements of its customers. These contracts include short-term and long-term commitments to purchase and sell energy and energy related products in the retail and wholesale markets with the intent and ability to deliver or take delivery. While these contracts are considered derivative financial instruments under SFAS No. 133, the majority of these transactions have been designated as "normal purchases" and "normal sales" and are not subject to the provisions of SFAS No. 133. Normal purchases and normal sales are contracts where physical delivery is probable, quantities are expected to be used or sold in the normal course of business over a reasonable period of time, and price is not tied to an unrelated underlying derivative. Under these contracts Exelon Generation recognizes gains or losses when the underlying physical transaction occurs. Revenues and expenses associated with market price risk management contracts are amortized over the terms of such contracts. The remainder of these contracts are generally considered cash flow hedges under SFAS No. 133.
F-12
Additionally, during 2001, as part of the creation of Exelon Generation's energy trading operation, Exelon Generation began to enter into contracts to buy and sell energy for trading purposes, subject to limits. These contracts are recognized on the balance sheet at fair value and changes in the fair value of these derivative financial instruments are recognized in earnings.
Prior to the adoption of SFAS No. 133, Exelon Generation applied hedge accounting only if the derivative reduced the risk of the underlying hedged item and was designated at the inception of the hedge, with respect to the hedged item. Exelon Generation recognized any gains or losses on these derivatives when the underlying physical transaction affected earnings.
Contracts entered into by Exelon Generation to limit market risk associated with forward energy commodity contracts are reflected in the financial statements at the lower or cost or market using the accrual method of accounting. Under these contracts Exelon Generation recognizes any gains or losses when the underlying physical transaction affects earnings. Revenues and expenses associated with market price risk management contracts were amortized over the terms of such contracts.
Recently Issued Accounting Standards
During 2001, the FASB issued SFAS No. 141, "Business Combinations" (SFAS No. 141), No. 142, "Goodwill and Other Intangible Assets" (SFAS No. 142), No. 143, "Asset Retirement Obligations" (SFAS No. 143) and No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets" (SFAS No. 144).
SFAS No. 141 requires that all business combinations be accounted for under the purchase method of accounting and establishes criteria for the separate recognition of intangible assets acquired in business combinations. SFAS No. 141 is effective for business combinations initiated after June 30, 2001. In addition, SFAS No. 141 requires that unamortized negative goodwill related to pre-July 1, 2001 purchase be allocated as a pro-rata reduction of the amounts that otherwise would have been assigned to the acquired assets. If any excess remains, that remaining excess is to be recognized as an extraordinary gain concurrent with the adoption of SFAS No. 142. Included on AmerGen's balance sheet is $43 million of negative goodwill net of accumulated amortization. Upon AmerGen's adoption of SFAS No. 141 in the first quarter of 2002. Exelon Generation expects to recognize its appropriate share of approximately $22 million, pre-tax, as a cumulative effect of a change in accounting principle.
SFAS No. 142 establishes new accounting and reporting standards for goodwill and intangible assets. Exelon Generation adopted SFAS No. 142 as of January 1, 2002. Under SFAS No. 142, goodwill will no longer be subject to amortization. After January 1, 2002, goodwill will be subject to an assessment for impairment using a fair value based test at least annually, or more frequently if events or circumstances indicate that goodwill might be impaired. An impairment loss would be reported as a reduction to goodwill and a charge to operating expense, except at the transition date, when the loss would be reflected as a cumulative effect of a change in accounting principle. As of December 31, 2001, Exelon Generation has no goodwill recorded on its consolidated balance sheet.
SFAS No. 143 provides accounting requirements for retirement obligations associated with tangible long-lived assets. Exelon Generation expects to adopt SFAS No. 143 on January 1, 2003. Retirement obligations associated with long-lived assets included within the scope of SFAS No. 143 are those for which there is a legal obligation to settle under existing or enacted law, statute, written or oral contract
F-13
or by legal construction under the doctrine of promissory estoppel. Adoption of SFAS No. 143 will change the accounting for the decommissioning of Exelon Generation's nuclear generating plants. Currently, Exelon Generation records the obligation for decommissioning ratably over the lives of the plants. The January 1, 2003 adoption of SFAS No. 143 will require a cumulative effect adjustment effective the date of adoption to adjust plant assets and decommissioning liabilities to the values they would have been had this standard been employed from the in-service dates of the plants. The effect of this cumulative adjustment will be to increase the decommissioning liability to reflect a full decommissioning obligation in current year dollars. Additionally, the SFAS No. 143 standard will require the accrual of an asset, to the extent allowable under the standard, related to the full amount of the decommissioning obligation, which will be amortized over the remaining lives of the plants. The net difference between the asset recognized and the liability recorded upon adoption of the standard will be charged to earnings and recognized as a cumulative effect, net of expected regulatory recovery. The decommissioning liability to be recorded represents an obligation for the future decommissioning of the plants, and as a result interest expense will be accrued on this liability until such time as the obligation is satisfied.
Exelon Generation is in the process of evaluating the impact of SFAS No. 143 on its financial statements, and cannot determine the ultimate impact of adoption at this time, however the cumulative effect could be material to Exelon's earnings. Additionally, although over the life of the plant the charges to earnings for the depreciation of the asset and the interest on the liability will be equal to the amounts currently recognized as decommissioning expense, the timing of those charges will change and in the near-term period subsequent to adoption, the depreciation of the asset and the interest on the liability could result in a significant increase in expense.
SFAS No. 144 establishes accounting and reporting standards for both the impairment and disposal of long-lived assets. SFAS No. 144 is effective for fiscal years beginning after December 15, 2001 and provisions of SFAS No. 144 are generally applied prospectively. Exelon Generation is in the process of evaluating the impact of SFAS No. 144 on its financial.
2. Merger
On October 20, 2000 Exelon became the parent corporation for PECO and ComEd as a result of the completion of the transactions contemplated by the Agreement and Plan of Exchange and Merger, as amended (Merger Agreement) among PECO, Unicom Corporation and Exelon. The Merger was accounted for using the purchase method of accounting, with PECO as acquirer.
F-14
The fair value of the assets acquired and liabilities assumed in the merger associated with the generation-related business of ComEd are summarized below:
| Current assets | $ | 704 | |
| Property, plant and equipment | 64 | ||
| Nuclear fuel | 669 | ||
| Deferred debits and other assets | 3,683 | ||
| 5,120 | |||
Current liabilities |
634 |
||
| Deferred credits and other liabilities | 3,086 | ||
| 3,720 | |||
| Net generation-related assets | $ | 1,400 | |
Exelon Generation has included the generation-related assets and liabilities of ComEd and the related results of operations in its consolidated financial statements beginning October 20, 2000. Exelon Generation's Statement of Changes in Member's Equity reflects the generation-related impacts of the Merger as a capital contribution from Exelon.
3. Corporate Restructuring
During January 2001, Exelon undertook a corporate restructuring to separate its generation and other competitive businesses from its regulated energy delivery businesses conducted by ComEd and PECO. As part of the restructuring, the generation-related operations, employees, assets, liabilities, and certain commitments of Exelon Corporation were transferred to Exelon Generation.
F-15
The assets and liabilities transferred to Exelon Generation as of January 1, 2001 were as follows:
| Assets | ||||
| Current assets | $ | 1,285 | ||
| Property, plant and equipment | 831 | |||
| Nuclear fuel | 896 | |||
| Nuclear decommissioning trust funds | 3,127 | |||
| Investments | 762 | |||
| Deferred income taxes | 337 | |||
| Note receivable from affiliate | 363 | |||
| Other noncurrent assets | 153 | |||
| Total assets transferred | 7,754 | |||
| Liabilities | ||||
| Note payable to member | 696 | |||
| Current liabilities | 1,146 | |||
| Long-term debt | 205 | |||
| Decommissioning obligation for retired plants | 1,301 | |||
| Other noncurrent liabilities | 1,970 | |||
| Total liabilities transferred | 5,318 | |||
| Net assets transferred | $ | 2,436 | ||
On January 1, 2001, a non-cash distribution of $174 million was made in connection with the elimination of certain intercompany transactions.
In connection with the restructuring, ComEd and PECO also assigned their respective rights and obligations under various power purchase and fuel supply agreements to Exelon Generation. Additionally, Exelon Generation entered into power purchase agreements (PPAs) to supply the capacity and energy requirements of ComEd and PECO.
4. Equity Investments
Sithe Energies, Inc.
On December 18, 2000, Exelon Generation acquired 49.9% of the outstanding common stock of Sithe for $696 million in cash and $8 million of acquisition costs. Sithe, headquartered in New York, is a leading independent power producer, with ownership interests in 27 facilities in North America. Sithe has net generation capacity of 3,371 MW, primarily in New York and Massachusetts, 2,651 MW under construction and 2,400 MW in advanced development.
Beginning December 18, 2002, Exelon Generation will have the right to purchase all (but not less than all) of the remaining outstanding shares of the Sithe common stock. The option expires on December 18, 2005. In addition, each of Sithe's other stockholder groups will have the right to require us to purchase all (but not less than all) of its shares during the same period in which Exelon Generation can exercise its option. At the end of that period, if no stockholder has exercised its option,
F-16
Exelon Generation will have a one-time option to purchase shares from the other stockholders to bring its holdings to 50.1% of the total outstanding shares. If Exelon Generation exercise its option or if all the stockholder groups exercise their put rights, the purchase price for 70% of the remaining 50.1% of the Sithe stock will be set at a fair market value plus a 10% premium in the case of a call or 10% discount in the case of a put, subject to a floor of $430 million and a ceiling of $650 million, and the remaining portion will be valued at fair market value, subject to a floor price of $141 million and a ceiling price of $330 million, plus, in each case, interest accrued from the beginning of the exercise period.
If Exelon Generation increases its ownership in Sithe to 50.1% or more, Sithe will become a consolidated subsidiary and Exelon Generation's financial results will include Sithe's financial results from the date of purchase. At December 31, 2001, Sithe had total assets of $4.2 billion and long-term debt of $2.3 billion, including $2.1 billion of non-recourse project debt, and excluding any non-recourse project debt associated with Sithe's equity investments. For the year ended December 31, 2001 Sithe had revenues of approximately $1 billion. In December 2001, Sithe entered into a new 18-month corporate credit facility for $500 million expiring in June 2003. As of December 31, 2001 Sithe had drawn approximately $176 million under this facility and extended approximately $161 million in letters of credit.
Exelon Generation's investment in Sithe as of December 31, 2001 and 2000 was $725 million and $704 million, respectively.
AmerGen Energy Company, LLC
Exelon Generation and British Energy, Inc, a wholly owned subsidiary of British Energy, plc, each own a 50% equity interest in AmerGen Energy Company, LLC (AmerGen). Established in 1997, AmerGen was formed to pursue opportunities to acquire and operate nuclear generation facilities in the North America. Currently, AmerGen owns and operates three nuclear generation facilities: Clinton Power Station (Clinton) located in Illinois, Three Mile Island (TMI) Unit 1 located in Pennsylvania, and Oyster Creek, which was acquired in August 2000, located in New Jersey. Oyster Creek was acquired from GPU, Inc. (GPU) for $10 million. Under the terms of the purchase agreement, GPU agreed to fund outage cots of $89 million, including the cost of fuel, for a refueling outage that occurred in 2000. AmerGen is repaying these costs to GPU in equal annual installments through 2009. In addition, AmerGen assumed full responsibility for the ultimate decommissioning of Oyster Creek. At the closing of the sale, GPU provided funding for the decommissioning trust of $440 million. In conjunction with this acquisition, AmerGen has received a fully funded decommissioning trust fund which has been computed assuming the anticipated costs to appropriately decommission Oyster Creek discounted to net present value using the NRC's mandated rate of 2%. As part of each acquisition, AmerGen entered into a power sales agreement with the seller. The agreement with the seller for Clinton calls for Exelon Generation to sell 75% of the output back to Illinois Power for a term expiring at the end of 2005. The agreements with the seller of TMI and Oyster Creek are for all of the output expiring in 2001 and 2003, respectively.
AmerGen maintains a nuclear decommissioning trust fund for each of its plants in accordance with NRC regulations and believes that amounts in these trust funds, together with the investment earnings
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thereon and additional contributions for Clinton from Illinois Power, will be sufficient to meet its decommissioning obligations.
Exelon Generation's investment in AmerGen as of December 31, 2001 and 2000 was $113 million and $44 million, respectively.
The table below presents summarized financial information for Sithe and AmerGen, Exelon Generation's unconsolidated equity affiliates:
| |
Year Ended December 31, |
||||||||
|---|---|---|---|---|---|---|---|---|---|
| Income Statement Information |
|||||||||
| 2001 |
2000 |
1999 |
|||||||
| Operating revenues | $ | 1,691 | $ | 1,675 | $ | 15 | |||
| Operating income | 297 | 546 | 4 | ||||||
| Income before extraordinary items and cumulative effect of change in accounting principle | (8 | ) | 254 | 4 | |||||
| Net income | $ | (8 | ) | $ | 254 | $ | 4 | ||
Year Ended December 31, |
|||||||
|---|---|---|---|---|---|---|---|
| Balance Sheet Information |
|||||||
| 2001 |
2000 |
||||||
| Current assets | $ | 745 | $ | 588 | |||
| Noncurrent assets | 5,126 | 3,930 | |||||
| Total assets | $ | 5,871 | $ | 4,518 | |||
| Current liabilities | 591 | 1,072 | |||||
| Noncurrent liabilities | 3,714 | 2,025 | |||||
| Members' capital | 80 | 80 | |||||
| Undistributed earnings (deficit) | 155 | (1 | ) | ||||
| Additional paid-in capital | 735 | 735 | |||||
| Retained earnings | 647 | 602 | |||||
| Accumulated other comprehensive income (loss) | (51 | ) | 5 | ||||
| Total capitalization and liabilities | $ | 5,871 | $ | 4,518 | |||
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5. Property, Plant and Equipment
A summary of property, plant and equipment by classification is as follows:
| |
December 31, |
||||||
|---|---|---|---|---|---|---|---|
| |
2001 |
2000 |
|||||
| Generation plant | $ | 4,344 | $ | 4,142 | |||
| Construction work-in-progress | 610 | 380 | |||||
| Total property, plant and equipment | 4,954 | 4,522 | |||||
| Less: accumulated depreciation (including decommissioning costs for active nuclear stations) | 3,794 | 3,691 | |||||
| Property, plant and equipment, net | $ | 1,160 | $ | 831 | |||
6. Jointly Owned Facilities—Property, Plant and Equipment
Exelon Generation's ownership interest in jointly owned generation plant at December 31, 2001 and 2000 were as follows:
| |
2001 |
|||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Plant |
||||||||||||||||
| Peach Bottom |
Salem |
Keystone |
Conemaugh |
Quad Cities |
||||||||||||
| Operator |
Exelon Generation |
PSEG Nuclear |
Sithe |
Sithe |
Exelon Generation |
|||||||||||
| Participating Interest | 50.00 | % | 42.59 | % | 20.99 | % | 20.72 | % | 75.00 | % | ||||||
| Generation plant | $ | 387 | $ | 12 | $ | 121 | $ | 193 | $ | 96 | ||||||
| Construction work-in-progress | 13 | 53 | 13 | 12 | 52 | |||||||||||
| Total property, plant and equipment | 400 | 65 | 134 | 205 | 148 | |||||||||||
| Accumulated depreciation | 220 | 4 | 98 | 124 | 10 | |||||||||||
| Property, plant and equipment, net | $ | 180 | $ | 61 | $ | 36 | $ | 81 | $ | 138 | ||||||
| |
2000 |
|||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Plant |
||||||||||||||||
| Peach Bottom |
Salem |
Keystone |
Conemaugh |
Quad Cities |
||||||||||||
| Operator |
Exelon Generation |
PSEG Nuclear |
Sithe |
Sithe |
Exelon Generation |
|||||||||||
| Participating Interest | 46.25 | % | 42.59 | % | 20.99 | % | 20.72 | % | 75.00 | % | ||||||
| Generation plant | $ | 378 | $ | 3 | $ | 120 | $ | 190 | $ | 84 | ||||||
| Construction work-in-progress | 41 | 41 | 4 | 10 | 38 | |||||||||||
| Total property, plant and equipment | 419 | 44 | 124 | 200 | 122 | |||||||||||
| Accumulated depreciation | 214 | 3 | 94 | 118 | 2 | |||||||||||
| Property, plant and equipment, net | $ | 205 | $ | 41 | $ | 30 | $ | 82 | $ | 120 | ||||||
Exelon Generation's undivided ownership interests are financed with Exelon Generation funds and, when placed in service, all operations are accounted for as if such participating interests were wholly owned facilities.
On September 30, 1999, PECO reached an agreement to purchase an additional 7.51% ownership interest in Peach Bottom Atomic Power Station (Peach Bottom) from Atlantic City Electric Company
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(ACE) and Delmarva Power & Light Company (DPL) for $18 million. With the purchase of the additional ownership interest in Peach Bottom, Exelon Generation received a transfer of $47 million representing ACE and DPL's decommissioning trust funds and the related liability for the station. As a result of the restructuring, the purchase agreement has been assigned to Exelon Generation. DPL's 3.755% interest was purchased in December 2000 by PECO and transferred to Exelon Generation as part of the restructuring. The purchase of ACE's 3.755% ownership interest was completed in October 2001.
7. Nuclear Decommissioning and Spent Fuel Storage
Nuclear Decommissioning
Exelon Generation has an obligation to decommission its nuclear power plants. Exelon Generation's current estimate of its nuclear facilities' decommissioning cost for its owned nuclear plants is $7.2 billion in current year (2002) dollars. Nuclear decommissioning activity occurs primarily after the plants retirement and is currently estimated to begin in 2031. Exelon Generation's Zion Station permanently ceased power generation operations in 1998. The plant is currently being maintained in a secure and safe condition until final decommissioning, which is scheduled to begin in 2013. Decommissioning costs are currently recoverable through the regulated rates of ComEd and PECO. Exelon Generation collected $102 million in 2001 from ComEd and PECO. At December 31, 2001, the decommissioning liability recorded in accumulated depreciation and deferred credits and other liabilities was $2.7 billion and $1.3 billion, respectively. At December 31, 2000, the decommissioning liability recorded in Accumulated Depreciation and deferred credits and other liabilities was $2.6 billion and $1.3 billion, respectively. In order to fund future decommissioning costs, at December 31, 2001 and 2000, Exelon Generation held $3.2 billion and $3.1 billion, respectively, in trust accounts which are included as investments in Exelon Generation's Consolidated Balance Sheets at their fair market value. These trust funds are either qualified or non-qualified. Section 468A of the Internal Revenue Code limits the amount of money that can be contributed into a "qualified fund." Contributions made into a qualified fund are tax deductible. Exelon Generation believes that the amounts being recovered from customers through regulated rates and earnings on nuclear decommissioning trust funds will be sufficient to fully fund its decommissioning obligations.
In connection with the transfer by ComEd of its nuclear generating stations to Exelon Generation, ComEd asked the Illinois Commerce Commission (ICC) to approve the continued recovery of decommissioning costs after the transfer. On December 20, 2000, the ICC issued an order finding that the ICC has the legal authority to permit ComEd to continue to recover decommissioning costs from customers for the six-year term of the power purchase agreements between ComEd and Exelon Generation. Under the ICC order, ComEd is permitted to recover $73 million per year from customers for decommissioning for the years 2001 through 2004. In 2005 and 2006, ComEd can recover up to $73 million annually, depending upon the portion of the output of the former ComEd nuclear stations that ComEd purchases from Exelon Generation. Under the ICC order, subsequent to 2006, there will be no further recoveries of decommissioning costs from customers. The ICC order also provides that any surplus funds after the nuclear stations are decommissioned must be refunded to customers. The ICC order is currently pending on appeal in the Illinois Appellate Court.
Exelon Generation recorded a receivable from ComEd of approximately $440 million representing ComEd's legal requirement to remit funds to Exelon Generation upon collection from customers, and
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for collections from customers prior to the establishment of external decommissioning trust funds in 1989 to be remitted to Exelon Generation for deposit into the decommissioning trusts through 2006. Unrealized gains and losses on decommissioning trust funds (based on the market value of the assets on the Merger date, in accordance with purchase accounting) had previously been recorded in accumulated depreciation. As a result of the transfer of the ComEd nuclear plants to Exelon Generation and the ICC order limiting the regulated recoveries of decommissioning costs, net unrealized losses of $23 million (net of income taxes) at that date were reclassified to accumulated other comprehensive income. All subsequent realized gains and losses on these decommissioning trust funds' assets are based on the cost basis of the trust fund assets established on the Merger date and are reflected in Other Income and Deductions in Exelon Generation's Consolidated Statements of Income.
Nuclear decommissioning costs associated with the nuclear generating stations formerly owned by PECO continue to be recovered currently through rates charged by PECO to regulated customers these amounts are remitted to Exelon Generation as allowed by the Pennsylvania Public Utility Commission.
Spent Fuel Storage
Under the Nuclear Waste Policy Act of 1982 (NWPA), the U.S. Department of Energy (DOE) is responsible for the selection and development of repositories for, and the disposal of, spent nuclear fuel and high-level radioactive waste (SNF). ComEd and PECO, as required by the NWPA, each signed a contract with the DOE (Standard Contract) to provide for disposal of SNF from their respective nuclear generating stations. In accordance with the NWPA and the Standard Contract, ComEd and PECO pay the DOE one mill ($.001) per kilowatt-hour of net nuclear generation for the cost of nuclear fuel long-term storage and disposal. This fee may be adjusted prospectively in order to ensure full cost recovery. The NWPA and the Standard Contract required the DOE to begin taking possession of SNF generated by nuclear generating units by no later than January 1998. The DOE, however, failed to meet that deadline and its performance is expected to be delayed significantly. The DOE's current estimate for opening an SNF facility is 2010. This extended delay in SNF acceptance by the DOE has led to Exelon Generation's use of dry storage at its Dresden and Peach Bottom Units and its consideration of dry storage at other units.
In July 2000, PECO entered into an agreement with the DOE relating to Peach Bottom nuclear generating unit to address the DOE's failure to begin removal of SNF in January 1998 as required by the Standard Contract. Under that agreement, the DOE agreed to provide credits against future contributions to the Nuclear Waste Fund over the next ten years to compensate for SNF storage costs incurred as a result of the DOE's breach of the contract. The agreement also provides that the DOE will take title to the SNF upon request and the interim storage facility at Peach Bottom provided certain conditions are met.
In November 2000, eight utilities with nuclear power plants filed a Joint Petition for Review against the DOE with the United States Court of Appeals for the Eleventh Circuit seeking to invalidate that portion of the agreement providing for credits against nuclear waste fund payments on the ground that such provision is a violation of the NWPA. PECO intervened as a defendant in that case, which is ongoing. In April, 2001, an individual filed suit against the DOE with the United States District Court for the Middle District of Pennsylvania seeking to invalidate the agreement on the grounds that the DOE has violated the National Environmental Policy Act and the Administrative Procedure Act. PECO
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intervened as a defendant and moved to dismiss the complaint. The Court has not yet ruled on the motion to dismiss.
The Standard Contract with the DOE also requires that PECO and ComEd pay the DOE a one-time fee applicable to nuclear generation through April 6, 1983. PECO's fee has been paid. Pursuant to the Standard Contract, ComEd elected to defer payment of the one-time fee of $277 million, with interest accruing to the date of payment, just prior to the first delivery of SNF to the DOE. As of December 31, 2001, the liability for the one-time fee with interest was $843 million.
The liabilities for spent nuclear fuel disposal costs, including the one-time fee, were transferred to Exelon Generation as part of the corporate restructuring.
8. Long-Term Debt
Long-term debt is comprised of the following:
| |
|
|
December 31, |
|||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|
| |
|
Maturity Date |
||||||||||
| |
Rates |
2001 |
2000 |
|||||||||
| Notes payable | 7.25 | % | 2003-2004 | $ | 9 | $ | 14 | |||||
| Senior unsecured notes | 6.95 | % | 2011 | 699 | — | |||||||
| Pollution control notes | 2.10%—2.70 | % | 2016-2034 | 317 | 195 | |||||||
| Total long-term debt | 1,025 | 209 | ||||||||||
| Due within one year | (4 | ) | (4 | ) | ||||||||
| Long-term debt | $ | 1,021 | $ | 205 | ||||||||
Long-term debt maturities in the period 2002 through 2006 and thereafter are as follows:
| 2002 | $ | 4 | |
| 2003 | 4 | ||
| 2004 | 1 | ||
| 2005 | — | ||
| 2006 | — | ||
| Thereafter | 1,016 | ||
| $ | 1,025 | ||
In May 2001, Exelon Generation entered into a forward-starting interest rate swap, with an aggregate notional amount of $700 million, to hedge the interest rate risk related to the anticipated issuance of debt. On June 11, 2001, Exelon Generation issued $700 million of senior unsecured notes with a maturity date of June 15, 2011 and an interest rate of 6.95% and closed the forward-starting interest rate swap. The aggregate loss on the settlement of the swap of $2 million, net of related income taxes, was classified in Accumulated Other Comprehensive Income and is being amortized to interest expense over the life of the debt.
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Also during 2001, Exelon Generation issued $121 million of Pollution Control Revenue Refunding Bonds at an average variable commercial paper interest rate of 2.685% with maturities of 20 to 33 years. The proceeds from these offerings were used to refund tax-exempt debt previously issued by PECO. The transaction was accounted for as a distribution to the member.
Exelon Generation, together with Exelon, ComEd and PECO, entered into a $1.5 billion 364 day unsecured revolving credit facility on December 12, 2001 with a group of banks. As of December 31, 2001, Exelon Generation did not meet the requirements to borrow under this facility.
9. Income Taxes
Income tax expense (benefit) is comprised of the following components for the years ended December 31:
| |
2001 |
2000 |
1999 |
|||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Included in operations: | ||||||||||||
| Federal: | ||||||||||||
| Current | $ | 253 | $ | 177 | $ | 92 | ||||||
| Deferred | 15 | (38 | ) | 18 | ||||||||
| Investment tax credit, net | (8 | ) | (13 | ) | (12 | ) | ||||||
| State: | ||||||||||||
| Current | 51 | 43 | 22 | |||||||||
| Deferred | 16 | (9 | ) | 5 | ||||||||
| $ | 327 | $ | 160 | $ | 125 | |||||||
| Included in cumulative effect of a change in accounting principle: | ||||||||||||
| Federal—deferred | $ | 6 | $ | — | $ | — | ||||||
| State—deferred | 1 | — | — | |||||||||
| $ | 7 | — | — | |||||||||
The effective income tax rate differed from the Federal statutory rate for the years ended December 31 principally due to the following:
| |
2001 |
2000 |
1999 |
|||||
|---|---|---|---|---|---|---|---|---|
| Income taxes on above at Federal statutory rate of 35% | 35.0 | % | 35.0 | % | 35.0 | % | ||
| Increase (decrease) due to: | ||||||||
| State income taxes, net of Federal income tax benefit | 5.2 | % | 5.0 | % | 5.2 | % | ||
| Nuclear decommissioning trust income | (0.6 | )% | 0.0 | % | — | |||
| Amortization of investment tax credit | (0.6 | )% | (1.9 | )% | (2.1 | )% | ||
| Other, net | — | — | (0.1 | )% | ||||
| Effective income tax rate | 39.0 | % | 38.1 | % | 38.0 | % | ||
F-23
The tax effect of temporary differences giving rise to Exelon Generation's deferred tax assets and liabilities as of December 31, 2001 and 2000 are presented below:
| |
2001 |
2000 |
||||||
|---|---|---|---|---|---|---|---|---|
| Deferred tax assets: | ||||||||
| Decommissioning and decontamination obligations | $ | 856 | $ | 455 | ||||
| Deferred pension and postretirement obligations | 236 | 227 | ||||||
| Deferred investment tax credits | 93 | 96 | ||||||
| Other, net | 110 | |||||||
| Total deferred tax assets | 1,185 | 888 | ||||||
| Deferred tax liabilities: | ||||||||
| Plant basis difference | (709 | ) | (397 | ) | ||||
| Unrealized gains on derivative financial instruments | (30 | ) | — | |||||
| Decommissioning and decontamination obligations | (100 | ) | (118 | ) | ||||
| Emission allowances | (44 | ) | (36 | ) | ||||
| Other, net | (12 | ) | — | |||||
| Total deferred tax liabilities | (895 | ) | (551 | ) | ||||
| Deferred income taxes net on the balance sheet | $ | 290 | $ | 337 | ||||
Prior to 2001, the offsetting deferred tax assets and liabilities resulting from decommissioning and decontamination assets and obligations, accounted for as regulatory assets and liabilities, were recorded within the plant basis difference caption above. As a result of the corporate restructuring, on January 1, 2001, the decommissioning and decontamination obligations were transferred to Exelon Generation. The deferred tax asset related to the decommissioning and decontamination obligation is no longer recorded in the plant basis difference caption with the regulatory assets and liabilities.
Included in accrued expenses on Exelon Generation's consolidated balance sheets at December 31, 2001 and 2000 was approximately $245 and $334 million current taxes payable due to the member.
The Internal Revenue Service and certain state tax authorities are currently auditing certain tax returns of Exelon's predecessor entities, Unicom and PECO. The current audits are not expected to have an adverse effect on financial condition or results of operations of Exelon Generation.
10. Employee Benefits
Exelon Generation has adopted defined benefit pension plans and postretirement welfare plans sponsored by Exelon. All Exelon Generation employees are eligible to participate in these plans. Essentially all Exelon Generation management employees, and electing union employees, hired on or after January 1, 2001 are eligible to participate in the newly established Exelon cash balance pension plan. Management employees who were active participants in the pension plans on December 31, 2000 and remain employed on January 1, 2002, will have the opportunity to continue to participate in the pension plans or to transfer to the cash balance plan. Benefits under these pension plans generally reflect each employee's compensation, years of service, and age at retirement. Funding is based upon actuarially determined contributions that take into account the amount deductible for income tax
F-24
purposes and the minimum contribution required under the Employee Retirement Income Security Act of 1974, as amended. The following tables provide a reconciliation of benefit obligations, plan assets, and funded status of Exelon Generation's proportionate interest in the Exelon plans.
| |
Pension Benefits |
Other Postretirement Benefits |
|||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| |
2001 |
2000 |
2001 |
2000 |
|||||||||
| Change in Benefit Obligation: | |||||||||||||
| Net benefit obligation at beginning of year | $ | 2,757 | $ | 893 | $ | 1,144 | $ | 351 | |||||
| Service cost | 37 | 17 | 17 | 11 | |||||||||
| Interest cost | 166 | 91 | 70 | 33 | |||||||||
| Plan participants' contributions | — | — | 2 | — | |||||||||
| Plan amendments | 19 | — | (105 | ) | — | ||||||||
| Actuarial (gain)loss | 102 | 102 | 72 | 77 | |||||||||
| Acquisitions | — | 1,689 | — | 670 | |||||||||
| Curtailments/Settlements | (16 | ) | (32 | ) | — | 2 | |||||||
| Special accounting costs | 13 | 90 | 2 | 25 | |||||||||
| Gross benefits paid | (202 | ) | (93 | ) | (70 | ) | (25 | ) | |||||
| Net benefit obligation at end of year | $ | 2,876 | $ | 2,757 | $ | 1,132 | $ | 1,144 | |||||
| Change in Plan Assets: | |||||||||||||
| Fair value of plan assets at beginning of year | $ | 2,908 | $ | 1,296 | $ | 635 | $ | 108 | |||||
| Actual return on plan assets | (111 | ) | 82 | (7 | ) | (6 | ) | ||||||
| Employer contributions | 14 | 1 | 40 | 40 | |||||||||
| Plan participants' contributions | — | — | 2 | 1 | |||||||||
| Acquisitions | — | 1,622 | — | 517 | |||||||||
| Gross benefits paid | (202 | ) | (93 | ) | (70 | ) | (25 | ) | |||||
| Fair value of plan assets at end of year | $ | 2,609 | $ | 2,908 | $ | 600 | $ | 635 | |||||
| Funded status at end of year | $ | (267 | ) | $ | 151 | $ | (532 | ) | $ | (509 | ) | ||
| Miscellaneous adjustment | — | — | — | 3 | |||||||||
| Unrecognized net actuarial (gain)loss | 110 | (347 | ) | 207 | 75 | ||||||||
| Unrecognized prior service cost | 46 | 33 | (105 | ) | — | ||||||||
| Unrecognized net transition obligation (asset) | (7 | ) | (9 | ) | 46 | 54 | |||||||
| Net amount recognized at end of year | $ | (118 | ) | $ | (172 | ) | $ | (384 | ) | $ | (377 | ) | |
F-25
| |
Pension Benefits |
Other Postretirement Benefits |
|||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| |
2001 |
2000 |
1999 |
2001 |
2000 |
1999 |
|||||||
| Weighted-average assumptions as of December 31, | |||||||||||||
| Discount rate | 7.35 | % | 7.60 | % | 8.00 | % | 7.35 | % | 7.60 | % | 8.00 | % | |
| Expected return on plan assets | 9.50 | % | 9.50 | % | 9.50 | % | 9.50 | % | 8.00 | % | 8.00 | % | |
| Rate of compensation increase | 4.00 | % | 4.30 | % | 5.00 | % | 4.00 | % | 4.30 | % | 5.00 | % | |
| Health care cost trend on covered charges | N/A | N/A | N/A | 10.00 | % | 7.00 | % | 8.00 | % | ||||
| decreasing to ultimate trend of 4.5% in 2008 | decreasing to ultimate trend of 5.0% in 2005 | decreasing to ultimate trend of 5.0% in 2006 | |||||||||||
| |
Pension Benefits |
Other Postretirement Benefits |
|||||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| |
2001 |
2000 |
1999 |
2001 |
2000 |
1999 |
|||||||||||||
| Components of net periodic | |||||||||||||||||||
| benefit cost (benefit): | |||||||||||||||||||
| Service cost | $ | 37 | $ | 17 | $ | 13 | $ | 17 | $ | 11 | $ | 8 | |||||||
| Interest cost | 166 | 91 | 65 | 70 | 33 | 20 | |||||||||||||
| Expected return on assets | (215 | ) | (131 | ) | (94 | ) | (46 | ) | (15 | ) | (6 | ) | |||||||
| Amortization of: | |||||||||||||||||||
| Transition obligation (asset) | (2 | ) | (2 | ) | (2 | ) | 4 | 4 | 4 | ||||||||||
| Prior service cost | 4 | 3 | 2 | (5 | ) | — | — | ||||||||||||
| Actuarial (gain) loss | (11 | ) | (11 | ) | (3 | ) | — | — | — | ||||||||||
| Curtailment charge (credit) | (6 | ) | (5 | ) | — | 4 | 10 | — | |||||||||||
| Settlement charge (credit) | (3 | ) | (7 | ) | — | — | — | — | |||||||||||
| Net periodic benefit cost (benefit) | $ | (30 | ) | $ | (45 | ) | $ | (19 | ) | 44 | $ | 43 | $ | 26 | |||||
| Special accounting costs | $ | 13 | $ | 90 | $ | — | $ | 2 | $ | 25 | $ | — | |||||||
| Sensitivity of retiree welfare results | ||||
| Effect of a one percentage point increase in assumed health care cost trend on total service and interest cost components | $ | 15 | ||
| on postretirement benefit obligation | $ | 135 | ||
| Effect of a one percentage point decrease in assumed health care cost trend on total service and interest cost components | $ | (12 | ) | |
| on postretirement benefit obligation | $ | (117 | ) |
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Prior service cost is amortized on a straight-line basis over the average remaining service period of employees expected to receive benefits under the plans.
Special accounting costs in 2000 of $90 million include $42 million for separation benefits and $48 million for plan enhancements. Exelon Generation provides certain health care and life insurance benefits for retired employees through plans sponsored by Exelon. In 2001, Exelon amended the postretirement medical benefit plan to change the eligibility requirement of the plan to cover only employees who retire with 10 years of service after age 45 rather than with 10 years of service and having attained the age of 55. Welfare benefits for active employees are provided by several insurance policies or self-funded plans whose premiums or contributions are based upon the benefits paid during the year.
Exelon Generation has savings plans for the majority of its employees. The plans allow employees to contribute a portion of their pretax income in accordance with specified guidelines. Exelon Generation matches a percentage of the employee contribution up to certain limits. The cost of Exelon Generation's matching contribution to the savings plans totaled $15 million in 2001.
Exelon Generation participates in a 401(k) Savings Plan for Employees sponsored by Exelon. The plan allows employees to contribute a portion of their pretax income in accordance with specified guidelines. Exelon Generation matches a percentage of employee contributions to the plan up to certain limits. Exelon Generation expensed matching contributions to the plan totaling $23 million for 2001, $7 million for 2000 and $3 million for 1999.
11. Commitments and Contingent Liabilities
Capital Expenditures
Generation's estimated capital expenditures for 2002 are as follows:
| |
(in millions) |
|||
|---|---|---|---|---|
| Production Plant | $ | 392 | ||
| Nuclear Fuel | 432 | |||
| Investments | 254 | |||
| Total | $ | 1,078 | ||
Capital expenditures for production include expenditures to increase capacity of existing plants.
Capital Commitments
Exelon Generation has committed to provide AmerGen with capital contributions equivalent to 50% of the purchase price of any acquisitions AmerGen makes in 2002 and Exelon Generation and British Energy have each agreed to provide up to $100 million to AmerGen at any time for operating expenses.
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Pending Acquisition
In December 2001, Exelon Generation agreed to purchase two generation plants located in the Dallas-Fort Worth metropolitan area from TXU Corp. (TXU) to expand its presence in the Texas region. The $443 million purchase (not included in above table) of the two natural-gas and oil-fired plants, to be funded through available cash and commercial paper proceeds, will add approximately 2,300 megawatts (MW) capacity. The transaction includes a power purchase agreement for TXU to purchase power during the months of May through September from 2002 through 2006. During the periods covered by the power purchase agreement, TXU will make fixed capacity payments and will provide fuel to Exelon Generation in return for exclusive rights to the energy and capacity of the generation plants. The closing of the acquisition is contingent upon receipt of the necessary regulatory approvals and is anticipated to occur in the second quarter of 2002.
Nuclear Insurance Coverages and Assessments
The Price-Anderson Act limits the liability of nuclear reactor owners for claims that could arise from a single incident. The current limit is $9.5 billion and is subject to change to account for the effects of inflation and changes in the number of licensed reactors. Exelon Generation carries the maximum available commercial insurance of $200 million and the remaining $9.3 billion is provided through mandatory participation in a financial protection pool. Under the Price-Anderson Act, all nuclear reactor licensees can be assessed up to $89 million per reactor per incident, payable at no more than $10 million per reactor per incident per year. This assessment is subject to inflation and state premium taxes. In addition, the U.S. Congress could impose revenue-raising measures on the nuclear industry to pay claims. Price-Anderson is scheduled to expire on August 1, 2002. Although replacement legislation has been proposed from time to time, Exelon Generation is unable to predict whether replacement legislation will be enacted.
Exelon Generation carries property damage, decontamination and premature decommissioning insurance for each station loss resulting from damage to its nuclear plants. In the event of an accident, insurance proceeds must first be used for reactor stabilization and site decontamination. If the decision is made to decommission the facility, a portion of the insurance proceeds will be allocated to a fund, which Exelon Generation is required by the NRC to maintain, to provide for decommissioning the facility. Exelon Generation is unable to predict the timing of the availability of insurance proceeds to Exelon Generation and the amount of such proceeds which would be available. Under the terms of the various insurance agreements, Exelon Generation could be assessed up to $121 million for losses incurred at any plant insured by the insurance companies. In the event that one or more acts of terrorism cause accidental property damage within a twelve month period from the first accidental property damage under one or more policies for all insureds, the maximum recovery for all losses by all insureds will be an aggregate of $3.2 billion plus such additional amounts as the insurer may recover for all such losses from reinsurance, indemnity, and any other source, applicable to such losses.
Additionally, Exelon Generation is a member of an industry mutual insurance company that provides replacement power cost insurance in the event of a major accidental outage at a nuclear station. The premium for this coverage is subject to assessment for adverse loss experience. Exelon Generation's maximum share of any assessment is $46 million per year.
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In addition, Exelon Generation participates in the American Nuclear Insurers Master Worker Program, which provides coverage for worker tort claims filed for bodily injury caused by a nuclear energy accident. This program was modified, effective January 1, 1998, to provide coverage to all workers whose "nuclear-related employment" began on or after the commencement date of reactor operations. Exelon Generation will not be liable for a retrospective assessment under this new policy. However, in the event losses incurred under the small number of policies in the old program exceed accumulated reserves, a maximum retroactive assessment of up to $50 million could apply.
Exelon Generation is self-insured to the extent that any losses may exceed the amount of insurance maintained. Such losses could have a material adverse effect on Exelon Generation's financial condition and results of operations.
Energy Commitments
Exelon Generation's wholesale operations include the physical delivery and marketing of power obtained through its generation capacity, and long, intermediate and short-term contracts. Exelon Generation maintains a net positive supply of energy and capacity, through ownership of generation assets and power purchase and lease agreements, to protect it from the potential operational failure of one of its owned or contracted power generation units. Exelon Generation has also contracted for access to additional generation through bilateral long-term power purchase agreements. These agreements are firm commitments related to power generation of specific generation plants and/or are dispatchable in nature—similar to asset ownership. Exelon Generation enters into power purchase agreements with the objective of obtaining low-cost energy supply sources to meet its physical delivery obligations to its customers. Exelon Generation has also purchased firm transmission rights to ensure that it has reliable transmission capacity to physically move its power supplies to meet customer delivery needs. The intent and business objective for the use of its capital assets and contracts are to provide Exelon Generation with physical power supply to enable it to deliver energy to meet customer needs. Exelon primarily uses financial contracts in its wholesale marketing activities for hedging purposes. Exelon also uses financial contracts to manage the risk surrounding trading for profit activities.
Exelon Generation has entered into bilateral long-term contractual obligations for sales of energy to ComEd, PECO and other load-serving entities, including electric utilities, municipalities, electric cooperatives, and retail load aggregators. Exelon Generation also enters into contractual obligations to deliver energy to wholesale market participants who primarily focus on the resale of energy products for delivery. Exelon Generation provides delivery of its energy to these customers through rights for firm transmission. In addition, Exelon Generation has entered into long-term power purchase agreements with independent power producers (IPP) under which Exelon Generation makes fixed capacity payments to the IPP in return for exclusive rights to the energy and capacity of the generation units for a fixed period.
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At December 31, 2001, Exelon Generation's long-term commitments, relating to the purchase and sale of energy, capacity and transmission rights from affiliated and unaffiliated entities are as expressed in the following tables:
| |
Unaffiliated |
Affiliated |
|||||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| |
Power Purchases |
Power Sales |
Capacity Purchases |
Transmission Rights Purchases |
Power Sale/ Capacity |
Power Purchases |
|||||||||||||
| 2002 | $ | 295 | $ | 1,803 | $ | 1,005 | $ | 139 | $ | 4,047 | $ | 256 | |||||||
| 2003 | 84 | 666 | 1,214 | 31 | 4,220 | 261 | |||||||||||||
| 2004 | 31 | 219 | 1,222 | 15 | 4,094 | 315 | |||||||||||||
| 2005 | 23 | 139 | 406 | 15 | 4,018 | 241 | |||||||||||||
| 2006 | 9 | 58 | 406 | 5 | 3,974 | 241 | |||||||||||||
| Thereafter | 150 | 22 | 3,657 | — | 6,207 | 2,171 | |||||||||||||
| Total | $ | 592 | $ | 2,907 | $ | 7,910 | $ | 205 | $ | 26,560 | $ | 3,485 | |||||||
Included in Exelon Generation's long-term commitments are PPAs with Midwest Generation, LLC Midwest Generation for the purchase of capacity from its coal fired stations, in declining amounts through 2004. Contracted capacity and capacity available through the exercise of an annual option are as follows (in megawatts):
| |
Contracted Capacity |
Available Option Capacity |
||
|---|---|---|---|---|
| 2002 | 4,013 | 1,632 | ||
| 2003 | 1,696 | 3,949 | ||
| 2004 | 1,696 | 3,949 |
The agreements with Midwest Generationa also provide for the option to purchase 2,698 megawatts of oil and gas-fired capacity, and 944 megawatts of peaking capacity, subject to reduction.
Exelon Generation has entered into PPAs with AmerGen, under which it will purchase all the energy from Unit No. 1 at TMI after December 31, 2001 through December 31, 2014. Under a 1999 PPA, Generation will purchase from AmerGen all of the residual energy from Clinton through December 31, 2002. Currently, the residual output approximates 25% of the total output of the Clinton facility.
Environmental Issues
Exelon Generation's operations have in the past and may in the future require substantial capital expenditures in order to comply with environmental laws. Additionally, under Federal and state environmental laws, Exelon Generation is generally liable for the costs of remediating environmental contamination of property now owned and of property contaminated by hazardous substances generated by Exelon Generation.
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As of December 31, 2001, Exelon Generation had accrued $14 million for environmental investigation and remediation costs. Exelon Generation cannot reasonably estimate whether it will incur other significant liabilities for additional investigation and remediation costs at these or additional sites identified by Exelon Generation, environmental agencies or others, or whether such costs will be recoverable from third parties.
Leases
Minimum future operating lease payments, including lease payments for real estate, rail cars and office equipment, as of December 31, 2001 were:
| 2002 | $ | 28 | |
| 2003 | 37 | ||
| 2004 | 26 | ||
| 2005 | 32 | ||
| 2006 | 32 | ||
| Thereafter | 527 | ||
| Total minimum future lease payments | $ | 682 | |
Rental expense under operating leases totaled $29 million $19 million and $18 million for the year ended December 31, 2001, 2000 and 1999, respectively.
Litigation
Cajun Electric Power Cooperative, Inc. On May 27, 1998, the United States Department of Justice, on behalf of the Rural Utilities Service and the Chapter 11 Trustee for the Cajun Electric Power Cooperative, Inc. (Cajun), filed an action claiming breach of contract against PECO in the United States District Court for the Middle District of Louisiana arising out of PECO's termination of the contract to purchase Cajun's interest in the River Bend nuclear power plant. Effective with the corporate restructuring, Exelon Generation has agreed to assume any liability and obligation arising from this litigation. During 2001, the parties reached a settlement of the dispute, and Exelon Generation made a payment of $14 million to Cajun.
Cotter Corporation. During 1989 and 1991, actions were brought in federal and state courts in Colorado against ComEd and its subsidiary, Cotter Corporation (Cotter), seeking unspecified damages and injunctive relief based on allegations that Cotter permitted radioactive and other hazardous material to be released from its mill into areas owned or occupied by the plaintiffs, resulting in property damage and potential adverse health effects. In 1994, a federal jury returned nominal dollar verdicts against Cotter on eight plaintiffs' claims in the 1989 cases, which verdicts were upheld on appeal. The remaining claims in the 1989 actions were settled or dismissed. In 1998, a jury verdict was rendered against Cotter in favor of 14 of the plaintiffs in the 1991 cases, totaling approximately $6 million in compensatory and punitive damages, interest and medical monitoring. On appeal, the Tenth Circuit Court of Appeals reversed the jury verdict, and remanded the case for new trial. These plaintiffs' cases were consolidated with the remaining 26 plaintiffs' cases, which had not been tried. The consolidated trial was completed on June 28, 2001. The jury returned a verdict against Cotter and
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awarded $16.3 million in various damages. On November 20, 2001, the District Court entered an amended final judgment which included an award of both pre-judgment and post-judgment interests, costs, and medical monitoring expenses which total $43.3 million. This matter is being appealed by Cotter in the Tenth Circuit Court of Appeals. Cotter will vigorously contest the award.
In November 2000, another trial involving a separate sub-group of 13 plaintiffs, seeking $19 million in damages plus interest was completed in federal district court in Denver. The jury awarded nominal damages of $42,500 to 11 of 13 plaintiffs, but awarded no damages for any personal injury or health claims, other than requiring Cotter to perform periodic medical monitoring at minimal cost. The plaintiffs appealed the verdict to the Tenth Circuit Court of Appeals.
On February 18, 2000, ComEd sold Cotter to an unaffiliated third party. As part of the sale, ComEd agreed to indemnify Cotter for any liability incurred by Cotter as a result of these actions, as well as any liability arising in connection with the West Lake Landfill discussed in the next paragraph.
The United States Environmental Protection Agency (EPA) has advised Cotter that it is potentially liable in connection with radiological contamination at a site known as the West Lake Landfill in Missouri. Cotter is alleged to have disposed of approximately 39,000 tons of soils mixed with 8,700 tons of leached barium sulfate at the site. Cotter, along with three other companies identified by the EPA as potentially responsible parties (PRPs), is reviewing a draft feasibility study that recommends capping the site. The PRPs are also engaged in discussions with the State of Missouri and the EPA. The estimated costs of remediation for the site are $10 to $15 million. Once a final feasibility study is complete and a remedy selected, it is expected that the PRPs will agree on an allocation of responsibility for the costs. Until an agreement is reached, Exelon Generation cannot predict its share of the costs.
In connection with the corporate restructuring, the responsibility to indemnify Cotter for any liability related to these matters was transferred to Exelon Generation. Management believes it has established an adequate contingent liability in connection with these proceedings.
Godley Park District Litigation. On April 18, 2001, the Godley Park District filed suit in Will County Circuit Court against ComEd and Exelon alleging that oil spills at Braidwood Station have contaminated the Park District's water supply. The complaint sought actual damages, punitive damages of $100 million and statutory penalties. The court dismissed all counts seeking punitive damages and statutory penalties, and the plaintiff has filed an amended complaint before the court. Exelon Generation is contesting the liability and damages sought by plaintiff.
Pennsylvania Real Estate Tax Appeals. Exelon Generation is involved in tax appeals regarding two of its nuclear facilities, Limerick (Montgomery County) and Peach Bottom (York County) and one of its fossil facilities, Eddystone (Delaware County), Exelon is also involved in the appeal for TMI (Dauphin County) through AmerGen. Exelon Generation does not believe the outcome of these matters will have a material adverse effect on Exelon Generation's results of operations or financial condition.
Enron. Exelon Generation is an unsecured creditor in Enron Corp.'s (Enron) bankruptcy proceeding. Exelon Generation's claim for power and other products sold to Enron in November and early December 2001 is $8.5 million. Enron may assert that Exelon Generation should not have closed
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out and terminated all of its forward contracts with Enron. If Enron is successful in this argument, Exelon Generation's exposure could be greater than $8.5 million. Exelon Generation may also be subject to exposure due to the credit policies of ISO-operated spot markets that allocate defaults of market participants to non-defaulting participants. Exelon Generation has established an allowance for uncollectibles in anticipation of resolution of these matters.
General. Exelon Generation is involved in various other litigation matters. The ultimate outcome of such matters, while uncertain, is not expected to have a material adverse effect on Exelon Generation's financial condition or results of operations.
12. Fair Value of Financial Assets and Liabilities
The carrying amounts and fair values of Exelon Generation's financial assets and liabilities as of December 31 were as follows:
| |
2001 |
2000 |
||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| |
Carrying Amount |
Fair Value |
Carrying Amount |
Fair Value |
||||||||||
| Non-derivatives | ||||||||||||||
| Assets: | ||||||||||||||
| Cash and cash equivalents | $ | 224 | $ | 224 | $ | 4 | $ | 4 | ||||||
| Customer accounts receivable | 316 | 316 | 316 | 316 | ||||||||||
| Nuclear decommissioning trust funds | 3,165 | 3,165 | 3,127 | 3,127 | ||||||||||
| Liabilities: | ||||||||||||||
| Long-term debt (including amounts due within one year) | 1,025 | 1,040 | 209 | 209 | ||||||||||
| Derivatives | ||||||||||||||
| Energy Derivatives | 92 | 92 | (34 | ) | (34 | ) | ||||||||
As of December 31, 2001 and 2000, Exelon Generation's carrying amounts of cash and cash equivalents and accounts receivable are representative of fair value because of the short-term nature of these instruments. Fair values of the trust accounts for decommissioning nuclear plants and long-term debt are estimated based on quoted market prices for the same or similar issues. The fair value of Exelon Generation's and power purchase and sale contracts is determined using quoted exchange prices, external dealer prices, or internal valuation models which utilize assumptions of future energy prices and available market pricing curves. The fair value of Exelon Generation's energy derivatives is reported in the balance sheet as current or non-current assets or liabilities depending on the time until settlement of the transaction. At December 31, 2001, the following amounts were reported in Exelon Generation's consolidated balance sheet for the fair value of energy derivatives: accounts receivable of $109 million; other non-current assets of $62; accounts payable of $71; and non-current liabilities of $8.
Financial instruments that potentially subject Exelon Generation to concentrations of credit risk consist principally of cash equivalents, customer accounts receivable and energy derivatives. Exelon Generation places its cash equivalents with high-credit quality financial institutions. Generally, such investments are in excess of the Federal Deposit Insurance Corporation limits.
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Exelon Generation utilizes derivatives to manage the utilization of its available generating capacity and provision of wholesale energy to its affiliates. Exelon Generation also utilizes energy option contracts and energy financial swap arrangements to limit the market price risk associated with forward energy commodity contracts. Additionally, Exelon Generation enters into certain energy-related derivatives for trading or speculative purposes. Exelon Generation would be exposed to credit-related losses in the event of non-performance by the counterparties that issued the derivative instruments. The credit exposure of derivatives contracts is represented by the fair value of contracts at the reporting date. The majority of power purchase and sale contracts are documented under master netting agreements.
On January 1, 2001, Exelon Generation recognized a non-cash gain of $12 million, net of income taxes, in earnings and deferred a non-cash gain of $5 million, net of income taxes, in accumulated other comprehensive income, a component of shareholders' equity, to reflect the initial adoption of SFAS No. 133, as amended. SFAS No. 133 must be applied to all derivative instruments and requires that such instruments be recorded in the balance sheet either as an asset or a liability measured at their fair value through earnings, with special accounting permitted for certain qualifying hedges.
During 2001, Exelon Generation recognized net gains of $16 million ($10 million, net of income taxes) relating to mark-to-market (MTM) adjustments of certain non-trading power purchase and sale contracts pursuant to SFAS No. 133. MTM adjustments on power purchase contracts are reported in fuel and purchased power and MTM adjustments on power sale contracts are reported as Operating Revenues in the Consolidated Statements of Income. During 2001, Exelon Generation recognized net gains aggregating $14 million ($10 million, net of income taxes) on derivative instruments entered into for trading purposes. Exelon Generation commenced financial trading in the second quarter of 2001. Gains and losses associated with financial trading are reported as either operating revenue or fuel and purchased power expense in the Consolidated Statements of Income. During 2001, no amounts were reclassified from accumulated other comprehensive income into earnings as a result of forecasted energy commodity transactions no longer being probable.
As of December 31, 2001, approximately $50 million of deferred net gains on derivative instruments accumulated in other comprehensive income are expected to be reclassified to earnings during the next twelve months. Amounts in accumulated other comprehensive income related to interest rate cash flows are reclassified into earnings when the forecasted interest payment occurs. Amounts in accumulated other comprehensive income related to energy commodity cash flows are reclassified into earnings when the forecasted purchase or sale of the energy commodity occurs. The majority of Exelon Generation's cash flow hedges are expected to settle within the next 3 years.
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Exelon Generation classifies investments in the trust accounts for decommissioning nuclear plants as available-for-sale. The following tables show the fair values, gross unrealized gains and losses and amortized costs bases for the securities held in these trust accounts.
| |
December 31, 2001 |
||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| |
Amortized Cost |
Gross Unrealized Gains |
Gross Unrealized Losses |
Estimated Fair Value |
|||||||||
| Equity securities | $ | 1,666 | $ | 130 | $ | (236 | ) | $ | 1,560 | ||||
| Debt securities: | |||||||||||||
| Government obligations | 882 | 28 | (3 | ) | 907 | ||||||||
| Other debt securities | 701 | 16 | (19 | ) | 698 | ||||||||
| Total debt securities | 1,583 | 44 | (22 | ) | 1,605 | ||||||||
| Total available-for-sale securities | $ | 3,249 | $ | 174 | $ | (258 | ) | $ | 3,165 | ||||
| |
December 31, 2000 |
|||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|
| |
Amortized Cost |
Gross Unrealized Gains |
Gross Unrealized Losses |
Estimated Fair Value |
||||||||
| Equity securities | $ | 1,712 | $ | 144 | $ | (180 | ) | $ | 1,676 | |||
| Debt securities: | ||||||||||||
| Government obligations | 940 | 40 | — | 980 | ||||||||
| Other debt securities | 470 | 8 | (7 | ) | 471 | |||||||
| Total debt securities | 1,410 | 48 | (7 | ) | 1,451 | |||||||
| Total available-for-sale securities | $ | 3,122 | $ | 192 | $ | (187 | ) | $ | 3,127 | |||
Net unrealized losses of $84 million and net unrealized gains of $5 million, respectively, were recognized in Accumulated Depreciation and Other Comprehensive Income in Exelon Generation's Consolidated Balance Sheets at December 31, 2001 and 2000, respectively.
| |
For the years ended December 31, |
||||||
|---|---|---|---|---|---|---|---|
| |
2001 |
2000 |
|||||
| Proceeds from sales | $ | 1,624 | $ | 265 | |||
| Gross realized gains | 76 | 9 | |||||
| Gross realized losses | (189 | ) | (46 | ) | |||
Net realized gains of $14 million and net realized losses of $37 million were recognized in Accumulated Depreciation in Exelon Generation's Consolidated Balance Sheets at December 31, 2001 and 2000, respectively, and $127 million of net realized losses was recognized in Other Income and Deductions in Exelon Generation's Consolidated Income Statements for 2001. The available-for-sale securities held at December 31, 2001 have an average maturity of eight to ten years.
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13. Selected Quarterly Data (Unaudited)
The information shown below, in the opinion of management, includes all adjustments, consisting only of normal or recurring accruals, necessary to a fair presentation of such amounts. Due to the seasonal nature of the generation business, quarterly amounts vary significantly during the year.
| |
Calendar Quarter Ended |
||||||||||||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| |
March 31, |
June 30, |
September 30, |
December 31, |
|||||||||||||||||||||
| |
2001 |
2000 |
2001 |
2000 |
2001 |
2000 |
2001 |
2000 |
|||||||||||||||||
| Revenues | $ | 1,628 | $ | 510 | $ | 1,618 | $ | 645 | $ | 2,292 | $ | 941 | $ | 1,510 | $ | 1,178 | |||||||||
| Operating income | $ | 268 | $ | 70 | $ | 113 | $ | 140 | $ | 225 | $ | 228 | $ | 266 | $ | 3 | |||||||||
| Income before cumulative effect of change in accounting principle | $ | 158 | $ | 88 | $ | 71 | $ | 147 | $ | 167 | $ | 164 | $ | 116 | ($ | 139 | ) | ||||||||
| Cumulative effect of a change in accounting principle | $ | 12 | — | — | — | — | — | — | — | ||||||||||||||||
| Net income (loss) | $ | 170 | $ | 88 | $ | 71 | $ | 147 | $ | 167 | $ | 164 | $ | 116 | ($ | 139 | ) | ||||||||
14. Related Party Transactions
Exelon Corporation
At December 31, 2000, Exelon Generation had a $696 million demand note payable, that was due no later than December 16, 2001, with Exelon related to the acquisition of Sithe, which was reflected in current liabilities in Exelon Generation's Consolidated Balance Sheet. Interest expense on the note payable was $23 million and $2 million for the years ended December 31, 2001 and 2000. The loan was repaid in full in June 2001.
Exelon Corporate Restructuring
At December 31, 2001, Exelon Generation had a long-term receivable of $291 million from ComEd resulting from the restructuring which is included in deferred debits and other assets, on Exelon Generation's consolidated balance sheet. This receivable represents ComEd's legal requirement to remit the recovery of decommissioning costs upon collection from the customers.
Exelon Business Service Company
Effective January 1, 2001, upon the corporate restructuring, Exelon Generation receives a variety of corporate support services from the Business Services Company (BSC), a subsidiary of Exelon, including executive management, legal, human resources, financial and information technology services. Such services are provided at cost including applicable overheads. Costs charged to Exelon Generation by BSC for the year ended December 31, 2001 were $78 million.
Power Purchase Agreements with ComEd and PECO
In connection with the restructuring transaction, ComEd and PECO entered into PPAs with Exelon Generation. Under the PPA between Exelon Generation and ComEd, Exelon Generation supplies all of ComEd's load requirements through 2004. Prices for energy vary depending upon the time of day and month of delivery, as specified in the PPA. During 2005 and 2006, ComEd will purchase energy and capacity from Exelon Generation, up to the available capacity of the nuclear
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generation plants formerly owned by ComEd and transferred to Exelon Generation. Under the terms of the PPA with ComEd, Exelon Generation is responsible for obtaining the required transmission for its supply. The PPA with ComEd also specifies that prior to 2005, ComEd and Exelon Generation will jointly determine and agree on a market-based price for energy delivered under the PPA for 2005 and 2006. In the event that the parties cannot agree to market-based prices for 2005 and 2006 prior to July 1, 2004, ComEd has the option of terminating its PPA effective December 31, 2004.
Exelon Generation has also entered into a PPA with PECO whereby Exelon Generation will supply all of PECO's load requirements through 2010. Prices for energy are equivalent to the net proceeds from sales of unbundled generation to PECO's provider of last resort customers at rates PECO is allowed to charge customers who do not choose an alternate generation supplier. Under the terms of PPA, PECO is responsible for obtaining the required transmission for its supply.
Intercompany power purchases pursuant to the PPAs for the year ended December 31, 2001 for ComEd and PECO were $2.6 billion and $1.2 billion, respectively. Prior to the restructuring, Exelon Generation recorded revenues of $871 million and $798 million related to sales of energy to PECO for 2000 and 1999, respectively. During 2000, Exelon Generation recorded revenue of $403 million related to sales of energy to ComEd.
AmerGen
Exelon Generation has entered into a PPA dated November 22, 1999 with AmerGen. Under this PPA, Exelon Generation has agreed to purchase from AmerGen all of the residual energy from the Clinton Power Station through December 31, 2002. Currently, the residual output approximates 25% of the total output of the Clinton Power Station. For the years ended December 31, 2001 and 2000, the amount of purchased power recorded in Consolidated Statements of Income is $57 million and $52 million, respectively. As of December 31, 2001 and 2000, Exelon Generation had a payable of $3.1 million and $2.9 million, respectively, resulting from this PPA.
In addition, under a service agreement dated March 1, 1999, Exelon Generation provides AmerGen with certain operation and support services to the nuclear facilities owned by AmerGen. This service agreement has an indefinite term and may be terminated by Exelon Generation or by AmerGen on 90 days' notice. Exelon Generation is compensated for these services in an amount agreed to in the work order but not less than the higher of the fully allocated costs for performing the services or the market price. For the years ended December 31, 2001, 2000 and 1999, the amount charged to AmerGen for these services was $80 million, $32 million and $1 million respectively. As of December 31, 2001 and 2000, Exelon Generation had a receivable of $47 million and $20 million respectively resulting from these services.
In February 2002, Exelon Generation entered into an agreement to loan AmerGen up to $75 million at an interest rate of one-month LIBOR plus 2.25%. As of March 1, 2002, AmerGen had borrowed $30 million under this agreement. The loan is due November 1, 2002.
Sithe Energies, Inc.
In August 2001, Exelon Generation recorded a $150 million note receivable from Sithe. Sithe used the proceeds from the note to repay its subordinated debt. The note has a maturity date of August 20,
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2004 and an interest rate of the Eurodollar rate, plus 2.25%. Sithe repaid this note in December 2001. For the year ended December 31, 2001, Exelon recorded $2.7 million of interest income on the note.
Beginning December 18, 2002, we will have the right to purchase all (but not less than all) of the remaining outstanding shares of the Sithe common stock. The option expires on December 18, 2005. In addition, each of Sithe's other stockholder groups will have the right to require us to purchase all (but not less than all) of its shares during the same period in which we can exercise our option. At the end of that period, if no stockholder has exercised its option, we will have a one-time option to purchase shares from the other stockholders to bring our holdings to 50.1% of the total outstanding shares. If we exercise our option or if all the stockholder groups exercise their put rights, the purchase price for 70% of the remaining 50.1% of the Sithe stock will be set at a fair market value plus a 10% premium in the case of a call or 10% discount in the case of a put, subject to a floor of $430 million and a ceiling of $650 million, and the remaining portion will be valued at fair market value subject to floor price of $141 million and a ceiling price of $330 million, plus, in each case, interest accrued from the beginning of the exercise period.
15. Change in Accounting Estimate
Effective April 1, 2001, Exelon Generation changed its accounting estimates related to the depreciation and decommissioning of certain generating stations. The estimated service lives were extended by 20 years for three nuclear stations, by periods of up to 20 years for certain fossil stations and by 50 years for a pumped storage station. Effective July 1, 2001, the estimated service lives were extended by 20 years for the remainder of Exelon Generation's operating nuclear stations. These changes were based on engineering and economic feasibility studies performed by Exelon Generation considering, among other things, future capital and maintenance expenditures at these plants. The extension of the estimated service lives for the nuclear generating facilities is subject to approval by the NRC. As a result of the change, depreciation and decommissioning expense for 2001 decreased $90 million ($54 million, net of income taxes). At the end of the year, annualized savings resulting from the change would be a decrease of $132 million ($79 million, net of income taxes).
16. Supplemental Financial Information
Supplemental Balance Sheet Information
| |
December 31, |
|||||
|---|---|---|---|---|---|---|
| |
2001 |
2000 |
||||
| Valuation Allowances | ||||||
| Allowance for Doubtful Accounts | $ | 17 | $ | 2 | ||
| Reserve for inventory obsolescence | $ | 12 | $ | 79 | ||
| Accumulated Amortization | ||||||
| Nuclear Fuel | $ | 1,838 | $ | 1,445 | ||
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Supplemental Income Statement Information
| |
For the Years Ended December 31, |
|||||||||
|---|---|---|---|---|---|---|---|---|---|---|
| |
2001 |
2000 |
1999 |
|||||||
| Taxes Other than Income | ||||||||||
| Real Estate | $ | 94 | $ | 32 | $ | 18 | ||||
| Payroll | 38 | 27 | 16 | |||||||
| Other | 17 | 5 | 3 | |||||||
| Total | $ | 149 | $ | 64 | $ | 37 | ||||
Other, Net |
||||||||||
| Investment Income | $ | (8 | ) | $ | 14 | — | ||||
| Other | 2 | 41 | ||||||||
| Total | $ | (8 | ) | $ | 16 | $ | 41 | |||
Supplemental Cash Flow Information
| |
For the Years Ended December 31, |
|||||||||
|---|---|---|---|---|---|---|---|---|---|---|
| |
2001 |
2000 |
1999 |
|||||||
| Cash paid during the year: | ||||||||||
| Interest (net of amount capitalized) | $ | 74 | $ | 35 | $ | 18 | ||||
| Income taxes (net of refunds) | $ | 335 | — | — | ||||||
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