ML051180145
| ML051180145 | |
| Person / Time | |
|---|---|
| Site: | Farley  |
| Issue date: | 04/15/2005 |
| From: | Derieux J Alabama Power Co |
| To: | Document Control Desk, Office of Nuclear Reactor Regulation |
| References | |
| Download: ML051180145 (57) | |
Text
J. Randy DeRieux 600 North 18th Street Assistant Treasurer and Post Office Box 2641 General Manager-Birmingham, Alabama 35291-0030 Corporate Finance and Planning Tel 205.257.2454 PlanningFax 205.257.1023 April 15, 2005 AABAMAA POWER A SOUTHERN COMPANY U. S. Nuclear Regulatory Commission Attn: Document Control Desk Washington, D. C. 20555-0001 Joseph M. Farley Nuclear Plant Annual Submission Reports Re: Docket Nos.:
50-348 50-364 Ladies & Gentlemen:
Enclosed is the annual submission of Alabama Power Company with respect to the retrospective premium guarantee required under the Price Anderson Act, as amended, applicable to its Joseph M. Farley Nuclear Plant. We have elected to satisfy this guarantee requirement by submitting annual certified financial statements and cash projections, showing that a cash flow can be generated and would be available for payment of retrospective premiums up to $20,000,000 within three months after submission of the statement. In this connection, enclosed are the following:
- 1. 2004 Annual Report which includes financial statements for the calendar year 2004, together with the report on such statements by Deloitte & Touche LLP, independent public accountants;
- 2. Unaudited Financial Statements for the quarter ended March 31, 2005;
- 3. Cash Flow Projections for the period January 1, 2005 through December 31, 2005, showing that cash flow of $20,000,000 can be generated and would be available for payment of retrospective premiums within three months after submission of the statement.
Please acknowledge receipt of the enclosures by signing and returning the enclosed copy of this letter.
Very truly yours, JRD:lw Enclosures cc:
w/enclosures Southern Nuclear Operating Company Mr. J. T. Gasser, Executive Vice President Mr. J. Randy Johnson, General Manager - Plant Farley U. S. Nuclear Requlatory Commission Dr. W. D. Travers, Regional Administrator Mr. S. E. Peters, NRR Project Manager - Farley Mr. C. A. Patterson, Senior Resident Inspector - Farley
ALABAMA POWER COMPANY STATEMENT OF INCOME (THOUSANDS OF DOLLARS) 3 Months Ended 3/31/2005 OPERATING REVENUES:
Revenues 969,736 OPERATING EXPENSES:
Operation --
Fuel Purchased & interchange power, net Other Maintenance Depreciation & amortization Taxes other than income taxes Federal and State income taxes 290,054 79,864 148,357 123,554 108,491 62,549 13,448 Total Operating Expenses 826,317 OPERATING INCOME OTHER INCOME (EXPENSES):
Allowance for equity funds used during construction Income from subsidiary Other, net 143,419 5,654 1,008 (363)
INCOME BEFORE INTEREST CHARGES 149,718 INTEREST CHARGES:
Interest on long-term debt Allowance for debt funds used during construction Amortization of debt discount, premium and expenses, net Other interest charges 46,891 (2,078) 3,753 1,678 Net Interest Charges 50,244 NET INCOME DIVIDENDS ON PREFERRED STOCK NET INCOME AFTER DIVIDENDS ON PREFERRED STOCK This statement reflects the usual accounting practices of the Company on the basis of interim figures and is subject to audit and end of year adjustments.
99,474 6,072 93,402
ALABAMA POWER COMPANY Internal Cash Flow for Joseph M. Farley Nuclear Power Station (Thousands of Dollars) 2004 Actual 2005 Projections Net Income Less Dividends Paid Retained Earnings Adjustments:
Depreciation and Amortization Deferred Income Taxes and Investment Tax Credits Allowance for Equity Used During Construction Total Adjustments 504,768 460,939 43,829 475,920 434,188 41,732 497,010 505,320 252,858 64,386 (16,141) 733,727 (18,180) 551,526 Internal Cash Flow 777,556 593,258 148,315 Average Quarterly Cash Flow 194,389 Percentage Ownership in all Operating Nuclear Units:
Joseph M. Farley Units 1 and 2 100%
Maximum Total Contingent Liability 20,000
p 1:
This statement reflects the usual accounting practices of the Company on the basis of Interim figures and Is subject to audit and end of year adjustments.
ALABAMA POWER COMPANY BALANCE SHEET CONSOLIDATED WITH ALABAMA POWER CAPITAL TRUSTS IV & V (Stated In Thousands of Dollars)
At March 31, 2005 At March 31, 2004 ASSETS UTILITY PLANT:
Plant in service, at original cost.............................................................................
Less - Accumulated provision for depreciation and amortization..........................
5$
S 14,780.404.00 5,758,038.00 Nuclear fuel, at amortized cost Construction work in Droaress..i...............................................................................
OTHER PROPERTY AND INVESTMENTS:
Equity investm ents In subsidiaries.........................................................................
Investment In unconsolidated subsidiaries............................................................
Nuclear decom m issioning trusts............................................................................
M iscellaneous........................................................................................................
CURRENT ASSETS:
Cash......................................................................................................................
Special Deposits....................................................................................................
Tem porary cash Investm ents.................................................................................
Investm ent securities.............................................................................................
Receivables -
Customer accounts receivable..
Other accounts and notes recei' Affiliated companies..................
Accumulated provision for unco Refundable Income taxes.............
Fossil fuel stock, at average cost.
Materials and supplies, at average Allowance Inventory......................
Prepayments -
ivable.................................................................
lltectible accounts..........................................
9,022,366.00 90,208.00 478,806.00 9,591.380.00 47,353.00 9,279.00 448,277.00 22,862.00 S
527,771.00 18,825.00 94,000.00 398,851.00 49,918.00 86,338.00 (6,882.00) 27,444.00 84,087.00 S
206,387.00 S
40,571.00 83,236.00 51,171.00 S
36,494.00 1,170,440.00 29,650.00 107,347.00 8,916.00 493,455.00 653,440.00 94,068.00 1.386.876.00 12,676.467.00 14,299,826 5,546,464 8,753,362 86,907 410,582 9,250,851 37,878 14,981 396,379 31,235 480,473 22,398 0
138,000 0
335,655 39,994 57,148 (5,868) 0 77,950 185,977 29,161 0
88,118 27,797 35,530 1,031,860 24,209 108,886 13,092 456,669 628,213 86,950 1,318,019 12,081,203 a cost................................................................
I..........................................................................
income taxes......................................................................................................
Other..................................................................................................................
Other current assets - SFAS 133..........................................................................
Vacation pay deferred............................................................................................
Debt expense, being am ortized.............................................................................
Debt redemption expense, being am ortized..........................................................
Accumulated miscellaneous operating provisions......................................
Prepaid pension cost.............................................................................................
Regulatory assets..................................................................................................
M iscellaneous........................................................................................................
TOTAL ASSETS......................................................................................................
4126,2OS +
This statement reflects the usual accounting practices of the Company on the basis of Interim figures and Is subject to audit and end of year adjustments.
ALABAMA POWER COMPANY BALANCE SHEET CONSOLIDATED WITH ALABAMA POWER CAPITAL TRUSTS IV & V (Stated In Thousands of Dollars)
CAPITALIZATION AND LIABILITIES CAPITALIZATION:
Com m on stock equity............................................................................................
Preferred stock......................................................................................................
Company obligated mandatorily redeemable preferred securities......................
Long-term debt......................................................................................................
CURRENT LIABILITIES:
Preferred stock due or to be redeemed within one year.......................................
Long-term debt due or to be redeemed within one year.......................................
Notes payable to banks.........................................................................................
Com m ercial paper................................................................................................
Accounts payable -
Affiliated com panies...........................................................................................
Athor
%.,UbLU[s r U sUp Taxes accrued -
Federal and state Incom e...................................................................................
Other..................................................................................................................
Interest accrued.....................................................................................................
Accrued Interest Payable to Unconsolidated Subs.........................................
Vacation pay accrued............................................................................................
M iscellaneous........................................................................................................
At March 31, 2005 3,605,473.00 464,948.00 S
309,279.00 S
4.105,527.00 S
8,485,227.00 S
S 225,005.00 S
S 109,265.00 S
144,393.00 S
51,460.00 S
37,881.00 48,335.00 51,744.00 8,119.00 36,494.00 S
65,290.00 S
777986.00 S
1,903.332.00 S
202,614.00 S
390,051.00 S
9,852.00 S
114,932.00 S
5,841.00 S
4,471.00 S
782,161.00 3,413,254.00 12,676,467.00 S
3,504,079 472,512 309,279 3.376.165 S
7.662,035 0
725,011 0
0 DEFERRED CREDITS AND OTHER LIABILITIES:
Accum ulated deferred Income taxes.....................................................................
Accumulated deferred investment tax credits........................................................
Asset Retirement Obligations................................................................................
Prepaid capacity revenues, net............................................................................
Regulatory liabilities..............................................................................................
Accumulated miscellaneous operating provisions.........................................
Natural disaster reserve........................................................................................
M iscellaneous........................................................................................................
At March 31, 2004 143,551 93,117 48,513 73,773 44,140 48,424 13,865 35,530 71,539 S
1,297,464 1,626,767 213,570 364.775 21,455 158,555 8,728 13,338 714,516 3,121,704 12,081,203 TOTAL CAPITALIZATION AND LIABILIT -
- Substantially ali assets of Alabama Power Capital Trust iv & v are junior subordinate notes tssued by the company. Upon redemption of such notes.
the Trust secutitIes wilbt e mandatorty redeemable. See Note 7 to te financa statements of Aabama Power Company of the 2002 Form 1O-K for further details.
4,26/2005 +
2004 Annual Report Alabama Power Company ALABAMA A POWER A SOUTHERN COMPANY
(,.
CONTENTS Alabama Power Company 2004 Annual Report I
SUMMARY
2 LETTER TO INVESTORS 3
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM 4
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION 22 FINANCIAL STATEMENTS 29 NOTES TO FINANCIAL STATEMENTS 48 SELECTED FINANCIAL AND OPERATING DATA 50 DIRECTORS AND OFFICERS 51 CORPORATE INFORMATION
SUMMARY
Percent 2004 2003 Change Financial Highlights (in millions):
Operating revenues
$4,236
$3,960 7.0 Operating expenses
$3,216
$2,945 9.2 Net income after dividends on preferred stock
$481
$473 1.8 Operating Data:
Kilowatt-hour sales (in millions):
Retail 54,244 52,208 3.9 Sales for resale - non-affiliates 15,483 17,086 (9.4)
Sales for resale - affiliates 7,234 9,422 (23.2)
Total 76,961 78,716 (2.2)
Customers served at year-end (in thousands) 1,385 1,370 1.1 Peak-hour demand (in megawatts) 10,938 10,462 4.5 Capitalization Ratios (percent):
Common stock equity 43.8 46.4 Preferred stock 5.6 4.9 Mandatorily redeemable preferred securities 4.0 Long-term debt payable to affiliated trusts 3.8 Long-term debt 46.8 44.7 (Excluding long-term debt due within one year)
Return on Average Common Equity (percent) 13.53 13.75 I
2004 Letter to Investors Alabama Power Company 2004 Annual Report As 2004 brought change and new challenges across the world, Alabama Power responded by focusing on the certainties of our business:
We know that our shareholders want us to provide the return we promised them.
We know our customers want reliable, affordable, environmentally friendly energy.
I am proud to report that we again met those expectations in 2004, without sacrificing the things that make Alabama Power what it is - a company of integrity, honesty and ethical behavior.
Last year, Alabama Power reclaimed the number one ranking in overall customer value, improving our scores in every customer class for the third year in a row. Our generating plants again far surpassed their goals, meeting the growing demand of our customers, and our reliability rate continued to be more than 99.9 percent. At the same time, our prices remained well below the national average.
We continued to reduce our impact on the environment, installing additional equipment and technology to reduce emissions from our generating plants. Our "Renew Our Rivers" program spread into Georgia, Mississippi and Florida, ensuring that waterways across the Southeast are cleaner.
Once again, Alabama Power met or surpassed all of its financial goals in 2004, enabling us to keep our promises to shareholders.
In addition to reaching our stated goals for earnings, reliability and customer service, Alabama Power also successfully responded to unexpected events. In September 2004, the worst storm in our company's history hit the Gulf Coast of Alabama and moved northward across our service territory. Hurricane Ivan caused substantial damage and left approximately 826,000 of Alabama Power's 1,370,000 customer accounts without electrical service. Within eight days, we restored service to 99 percent of those customers. Within two weeks, power was restored to all who could receive service.
While we're proud of our accomplishments in 2004, we know we can't focus on the past or solely on ourselves. Our industry is increasingly impacted by national and global issues and events, and you can be assured that Alabama Power is aware of, and prepared to meet, the challenges ahead.
At the same time, we will continue to live the philosophy that has guided Alabama Power for almost a century. As always, we will make every decision with the best interests of our customers, shareholders and employees in mind.
I have every confidence this philosophy will lead to continued success in 2005 and beyond.
Sincerely, Charles D. McCrary President and Chief Executive Officer 2
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM Alabama Power Company:
We have audited the accompanying balance sheets and statements of capitalization of Alabama Power Company (a wholly owned subsidiary of Southern Company) as of December 31,2004 and 2003, and the related statements of income, comprehensive income, common stockholder's equity, and cash flows for each of the three years in the period ended December 31, 2004. These financial statements are the responsibility of Alabama Power Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also 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, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the finaricial statements (pages 22 to
- 47) present fairly, in all material respects, the financial position of Alabama Power Company at December 31, 2004 and 2003, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2004, in conformity with accounting principles generally accepted in the United States of America.
As discussed in Note I to the financial statements, in 2003 Alabama Power Company changed its method of accounting for asset retirement obligations.
Birmingham, Alabama February 28, 2005 I
MANAGEMIENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION Alabama Power Company 2004 Annual Report OVERVIEW Business Activities Alabama Power Company (the Company) operates as a vertically integrated utility providing electricity to retail customers within its traditional service area located within the State of Alabama and to wholesale customers in the Southeast.
Many factors affect the opportunities, challenges, and risks of the Company's primary business of selling electricity. These factors include the ability to maintain a stable regulatory environment, to achieve energy sales growth while containing costs, and to recover costs related to growing demand and increasingly more stringent environmental standards.
On September 15 and 16, 2004, Hurricane Ivan hit the Gulf Coast of Florida and Alabama and continued north through the state of Alabama, causing substantial damage in the service territory of the Company.
Approximately 826,000 of the Company's 1,370,000 customer accounts were without electrical service immediately after the hurricane. Almost 95% of those without power had service restored within one week, and two weeks after the storm, power had been restored to all who could receive service.
In 2004, the Company completed a retail rate proceeding that should help enable the recovery of substantial capital investments associated with environmental improvements.
Key Performtance Indficators In striving to maximize shareholder value while providing low-cost energy to nearly 1.4 million customers, the Company focuses on several key indicators. These indicators include customer satisfaction, peak season equivalent forced outage rate (Peak Season EFOR), and return on equity (ROE). The Company's financial success is directly tied to the satisfaction of its customers.
Key elements of ensuring customer satisfaction include outstanding service, high reliability, and competitive prices. Management uses nationally recognized customer satisfaction surveys and reliability indicators to evaluate the Company's results. Peak Season EFOR is an indicator of plant availability and efficient generation fleet operations during the months when generation needs are greatest. The rate is calculated by dividing the number of hours of forced outages by total generation hours. ROE is a performance standard used by both the investment community and many regulatory agencies. The Company's 2004 results compared with its targets for each of these indicators are reflected in the following chart.
Key 2004 2004 Performance Target Actual Indicator Performance Performance Customer Top quartile in Satisfaction national and Top quartile regional surveys I_______
Peak Season EFOR 2.81 % or less 1.86%
ROE 13.50%
13.53%
The strong financial performance achieved in 2004 reflects the focus that management places on these indicators, as well as the commitment shown by the Company's employees in achieving or exceeding management's expectations.
Earnings The Company's 2004 net income after dividends on preferred stock was $481 million, representing an S8 million (1.8 percent) increase from the prior year. This improvement is due primarily to higher retail sales, increases in other revenues, and lower interest expense, partially offset by higher non-fuel operating expenses.
The Company's 2003 net income after dividends on preferred stock was $473 million, representing a $12 million (2.5 percent) increase from the prior year. This improvement was due primarily to higher retail sales, higher sales for resale, increases in other revenues, and lower interest expense, partially offset by higher non-fuel operating expenses. In 2002, earnings were $461 million, representing a 19.3 percent increase from the prior year.
This improvement was primarily attributable to increased territorial energy sales and higher retail rates when compared to the prior year. More favorable weather conditions in 2002 as compared to the unusually mild weather experienced in 2001 contributed to the increases in territorial sales. The increases in revenues were partially offset by increased non-fuel operating expenses.
The return on average common equity for 2004 was 13.53 percent compared to 13.75 percent in 2003 and 13.80 percent in 2002.
4
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2004 Annual Report RESULTS OF OPERATIONS A condensed income statement is as follows:
Increase (Decrease)
Amount From Prior Year 2004 2004 2003 2002 (in millions)
Operating revenues
$4,236 S276 S250 $124 Fuel 1,187 119 98 (31)
Purchased power 413 98 66 (44)
Other operation and maintenance 947 26 67 71 Depreciation and amortization 426 13 15 15 Taxes other than income taxes 243 14 11 2
Total operating expenses 3,216 270 257 13 Operating income 1,020 6
(7) 111 Total other income and (expense)
(202) 30 20 6
Income taxes 313 23 (2) 44 Net income 505 13 15 73 Dividends on preferred stock 24 5
3 (1)
Net income after dividends on preferred stock
$ 481 S 8 $ 12 $ 74 Retail revenues in 2004 were $3.3 billion. Revenues increased $242 million (7.9 percent) from the prior year, increased $100 million (3.4 percent) in 2003, and increased $203 million (7.4 percent) in 2002. All sectors of retail revenues increased $68 million (3.7 percent) for the Company in 2004. These 2004 and 2003 increases were primarily due to increased fuel revenue and 2.6 percent and 0.8 percent increases in retail base rates which went into effect in July 2003 and July 2004, respectively.
See Note 3 to the financial statements under "Retail Rate Adjustment Procedures" for additional information.
The primary contributors to the increase in revenues in 2002 were the positive effect of favorable weather conditions on energy sales and increases in retail base rates (0.6 percent increase in July 2001 and 2 percent increases in both October 2001 and April 2002). The Company mitigated the effect of these increases to customers with a decrease to the energy cost recovery factor in April 2002.
Fuel rates billed to customers are designed to fully recover fluctuating fuel and purchased power costs over a period of time. At December 31, 2004, the Company had
$102 million of unrecovered fuel costs. Fuel revenues generally have no effect on net income because they represent the recording of revenues to offset fuel and purchased power expenses.
Sales for resale to non-affiliates are predominantly unit power sales under long-term contracts to Florida utilities. Revenues from power sales contracts have both capacity and energy components. Capacity revenues reflect the recovery of fixed costs and a return on investment under the contracts. Energy is generally sold at variable cost. These capacity and energy components of the unit power contracts were as follows:
Revenues Operating revenues for 2004 were $4.2 billion, reflecting a
$276 million increase from 2003. The following table summarizes the principal factors that have affected operating revenues for the past three years:
Amount 2004 2003 2002 (in millions)
Retail -- prior year
$3,051
$2,951
$2,748 Change in -
Base rates 41 51 76 Sales growth 48 68 70 Weather 12 (61) 60 Fuel cost recovery and other 141 42 (3)
Retail -- current year 3,293 3,051 2,951 Sales for resale --
Non-affiliates 484 488 474 Affiliates 308 277 188 Total sales for resale 792 765 662 Other operating revenues 151 144 97 Total operating revenues S4,236
$3,960
$3,710 Percent change 7.0%
6.7%
3.5%
2004 2003 (in thousands) 2002 Unit power -
Capacity Energy Total
$134,615 $130,022 $119,193 146,809 145,342 134,051 S281.424 $275.364 S253.244 7
No significant declines in the amount of capacity are scheduled until the termination of the contracts in 2010.
Short-term opportunity energy sales are also included in sales for resale to non-affiliates. These opportunity sales are made at market based rates that generally provide a margin above the Company's variable cost to produce S
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2004 Annual Report the energy. Revenues associated with other power sales to non-affiliates were as follows:
2004 2003 (in thousands) 2002 Energy Sales Changes in revenues are influenced heavily by the volume of energy sold each year. Kilowatt-hour (KWH) sales for 2004 and the percent change by year were as follows:
KWH Percent Change 2004 2004 2003 2002 (millions)
Other power sales -
Capacity and other S 90,673 $ 96,263 $ 81,884 Variable cost of energy 111,742 115,829 139,162 Total
$202,415 $212,092 $221,046 Revenues from sales to affiliated companies within the Southern Company electric system, as well as purchases of energy, will vary from year to year depending on demand and the availability and cost of generating resources at each company. These affiliated sales and purchases are made in accordance with the affiliated company interchange agreements as approved by the Federal Energy Regulatory Commission (FERC). In 2004, sales for resale revenues increased $31 million primarily due to increases in fuel-related expenses. Sales for resale revenues increased $89.1 million in 2003 due to increased capacity payments received from affiliates. Excluding the capacity revenues, these transactions do not have a significant impact on earnings since the energy is generally sold at marginal cost and energy purchases are generally offset by energy revenues through the Company's energy cost recovery clause.
Other operating revenues in 2004 increased $7.0 million (4.9 percent) from 2003 due to an increase of $7.7 million in revenues from gas-fueled co-generation steam facilities -- primarily as a result of higher gas prices - and a $2.4 million increase in revenues from rent from electric property offset by a $2.0 million decrease in transmission revenues. Since co-generation steam revenues are generally offset by fuel expense, these revenues did not have a significant impact on earnings.
Other operating revenues in 2003 increased $47 million (48.6 percent) from 2002 due to an increase of
$19.4 million in revenues from gas-fueled co-generation steam facilities -- primarily as a result of higher gas prices
-- and a $14.8 million increase in revenues from Alabama Public Service Commission (Alabama PSC) approved fees charged to customers for connection, reconnection, and collection when compared to the same period in 2002.
Residential Commercial Industrial Other Total retail Sales for resale -
Non-affiliates Affiliates Total 17,368 13,823 22,855 198 54,244 2.4%
2.8 5.8 (2.4) 3.9 (2.5)%
0.7 2.3 (1.1) 0.3 9.6%
4.4 3.1 3.7 5.5 15,483 (9.4) 7,234 (23.2) 76,961 (2.2) 9.9 1.8 6.5 2.9 4.1 Energy sales in the residential sector grew by 2.4 percent in 2004 due primarily to continued customer growth and a return to normal summer temperatures.
Commercial sales increased 2.8 percent in 2004 primarily due to the State of Alabama's continuing transition from a manufacturing-based economy to a more service-based economy. Industrial sales rebounded 5.8 percent during the year with primary metal, chemical, and paper sectors leading the growth.
In 2003, residential energy sales experienced a 2.5 percent decrease over the prior year and total retail energy sales grew by 0.3 percent primarily as a result of milder-than-normal summer temperatures compared to the previous year. Although retail sales to industrial customers increased 2.3 percent in 2003 and 3.1 percent in 2002, overall sales to industrial customers remained depressed due to the continuing effect of sluggish economic conditions.
Residential energy sales for 2002 experienced a 9.6 percent increase over the prior year and total retail energy sales grew by 5.5 percent primarily as a result of warmer summer temperatures and colder winter weather conditions compared to the previous year.
The $11 million (9.9 percent) decrease in other operating revenues in 2002 resulted primarily from a $7.0 million decrease in revenues from gas-fueled co-generation steam facilities due to lower gas prices and lower demand.
Assuming normal weather, sales to retail customers are projected to grow approximately 1.7 percent annually on average during 2005 through 2009.
6
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2004 Annual Report Expenses Total operating expenses in 2004 grew $270 million (9.2 percent) to $3.2 billion. This increase over the previous year was primarily related to an increase in natural gas and coal prices. In addition, purchased power expenses increased S98 million (31.0 percent) primarily due to a 71.7 percent increase in energy purchased, while purchased power prices decreased by 1.9 percent. Depreciation and amortization expense increased $13 million (3.1 percent) primarily due to an increase in utility plant in service.
The total operating expenses in 2003 were approximately $3.0 billion, an increase of $257 million (9.6 percent) over the previous year. This increase is mainly due to a $98 million increase in fuel expense primarily related to an increase in the average cost of natural gas and coal. In addition, purchased power expenses increased a total of $66 million, maintenance expense increased $30 million primarily related to transmission and distribution overhead lines, and depreciation and amortization expense increased
$15 million.
In 2002, total operating expenses of $2.7 billion increased by $13 million (0.5 percent) over the previous year. This slight increase was mainly due to a $35 million increase in administrative and general expenses primarily related to employee salaries, insurance expense, and accrued expenses for liability insurance, litigation, and workers compensation, a $19 million increase in production expenses related to boiler plant maintenance, and a $15 million increase in depreciation and amortization expenses due to an increase in depreciable property. These increases were offset by a $43 million decrease in purchased power expenses and a $14 million decrease in fuel expenses related to lower coal prices.
Fuel costs constitute the single largest expense for the Company. The mix of fuel sources for generation of electricity is determined primarily by demand, the unit cost of fuel consumed, and the availability of fossil and nuclear generating units and hydro generation. The amount and sources of generation and the average cost of fuel per net kilowatt-hour (KWH) generated and the average cost of purchased power were as follows:
Total generation (billions of KWVls)
Sources of generation (percent) -
Coal Nuclear Hydro Gas Average cost of fuel per net KWH generated (cents)
Average cost of purchased power per net KWH (cents) 2004 2003 2002 70 72 71 65 64 62 19 19 19 6
8 6
10 9
13 1.69 1.54 1.44 4.79 3.61 2.91 Fuel and purchased power expenses totaled $1.6 billion in 2004, an increase of $216 million (15.6 percent). This was due to the average natural gas prices increasing by 30.5 percent, the average coal prices increasing 3.1 percent over the previous year, and higher capacity payments associated with an existing power purchase agreement (PPA). In 2003, total fuel and purchased power expenses of $1.4 billion increased $164 million (13.4 percent) over 2002 due to a 58.3 percent increase in average gas prices and a 2.2 percent increase in average coal prices. Fuel and purchased power expenses in 2002 of S 1.2 billion decreased $75 million (5.8 percent) due primarily to lower average fuel cost, while total energy sales increased 3.0 billion KWHs (4.1 percent) compared with the amounts recorded in 2001.
A significant upward trend in the cost of coal and natural gas has emerged since 2003, and volatility in these markets is expected to continue. Increased coal prices have been influenced by a worldwide increase in demand as a result of rapid economic growth in China as well as by increases in mining costs. Higher natural gas prices in the United States are the result of slightly lower gas supplies despite increased drilling activity.
Natural gas supply interruptions, such as those caused by the 2004 hurricanes, result in an immediate market response; however, the impact of this price volatility may be reduced by imports of natural gas and liquefied natural gas. Fuel expenses, including purchased power, are offset by fuel revenues through the Company's energy cost recovery clause and generally have no effect on net income.
Purchased power consists of purchases from affiliates in the Southern Company electric system and non-affiliated companies. Purchased power transactions among the Company and its affiliates will vary from period to period depending on demand, the availability, and the variable production cost of generating resources at 7
MANAGEM1ENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2004 Annual Report each company. Purchased power from non-affiliates increased $75 million (68 percent) in 2004. This was due to a 71.7 percent increase in energy purchased offset by a 1.9 percent decrease in purchased power prices over the previous year. In 2003, purchased power from non-affiliates increased $20 million (22 percent) due to a 19.3 percent increase in price and a 9.5 percent increase in energy purchased when compared to 2002. During 2002, purchased power transactions from non-affiliates decreased $54 million (37 percent) due to the addition in May 2001 of a combined cycle unit which generated 6.1 billion KWHs in 2002, an 18.4 percent increase over the previous year.
Depreciation and amortization expense increased 3.1 percent in 2004, 3.6 percent in 2003, and 3.9 percent in 2002. These increases reflect additions to property, plant, and equipment.
Allowance for equity funds used during construction (AFUDC) increased $3.5 million (28.2 percent) in 2004 due primarily to an increase in the amount of construction work in progress over the prior year. AFUDC increased $1.4 million (12.8 percent) in 2003 due to an increase in the applicable AFUDC rate.
AFUDC increased S4 million (57.5 percent) in 2002 due to an increase in the amount of construction work in progress over the prior year. See Note I to the financial statements under "AFUDC" for additional information.
Interest expense, net of amounts capitalized of $194 million in 2004 decreased $20.7 million (9.7 percent) from 2003, which had decreased S11.4 million (5.1 percent) from 2002, which had decreased $21 million (8.4 percent) from 2001. All years reflect a decrease in interest rates on long-term debt due to refinancing activities.
Effects of Inflation The Company is subject to rate regulation that is based on the recovery of historical costs. In addition, the income tax laws are based on historical costs. Therefore, inflation creates an economic loss because the Company is recovering its costs of investments in dollars that have less purchasing power. While the inflation rate has been relatively low in recent years, it continues to have an adverse effect on the Company because of the large investment in utility plant with long economic lives.
Conventional accounting for historical cost does not recognize this economic loss nor the partially offsetting gain that arises through financing facilities with fixed-money obligations, such as long-term debt and preferred securities. Any recognition of inflation by regulatory authorities is reflected in the rate of return allowed in the Company's approved electric rates.
FUTURE EARNINGS POTENTIAL General The Company operates as a vertically integrated utility providing electricity to retail customers within its traditional service area located in the State of Alabama and to wholesale customers in the Southeast. Prices for electricity provided by the Company to retail customers are set by the Alabama PSC under cost-based regulatory principles. Prices for electricity relating to jointly owned generating facilities, interconnecting transmission lines, and the exchange of electric power are set by the FERC.
Retail rates and earnings are reviewed and adjusted periodically within certain limitations based on ROE. See ACCOUNTING POLICIES - "Application of Critical Accounting Policies and Estimates - Electric Utility Regulation" herein and Note 3 to the financial statements for additional information about these and other regulatory matters.
The results of operations for the past three years are not necessarily indicative of future earnings potential.
The level of the Company's future earnings depends on numerous factors that affect the opportunities, challenges, and risks of the Company's primary business of selling electricity. These factors include the Company's ability to maintain a stable regulatory environment, to achieve energy sales growth while containing costs, and to recover costs related to growing demand and increasingly more stringent environmental standards. Future earnings for the electricity business in the near term will depend, in part, upon growth in energy sales, which is subject to a number of factors. These factors include weather, competition, new energy contracts with neighboring utilities, energy conservation practiced by customers, the price of electricity, the price elasticity of demand, and the rate of economic growth in the Company's service area.
Since 2001, merchant energy companies and traditional electric utilities with significant energy marketing and trading activities have come under severe financial pressures. Many of these companies have completely exited or drastically reduced all energy marketing and trading activities and sold foreign and domestic electric infrastructure assets. The Company has not experienced any material adverse financial impact 1
8
MANAGENIENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2004 Annual Report regarding its limited energy trading operations through Southern Company Services, Inc. (SCS).
Environmental AMatters New Source Review Actions In November 1999, the Environmental Protection Agency (EPA) brought a civil action in the U.S. District Court for the Northern District of Georgia against the Company, alleging that the Company had violated the New Source Review (NSR) provisions of the Clean Air Act and related state laws with respect to coal-fired generating facilities at the Company's Plants Miller, Barry, and Gorgas. The EPA concurrently issued to the Company a notice of violation relating to these specific facilities, as well as Plants Greene County and Gaston. In early 2000, the EPA filed a motion to amend its complaint to add the violations alleged in its notice of violation. The civil action requests penalties and injunctive relief, including an order requiring the installation of the best available control technology at the affected units. The action against the Company was effectively stayed in the spring of 2001 pending the appeal of a similar NSR action against the Tennessee Valley Authority before the U.S. Court of Appeals for the Eleventh Circuit. In June 2004, following the final resolution of that appeal, the U.S. District Court for the Northern District of Alabama lifted the stay in the action against the Company, placing the case back onto the court's active docket. See Note 3 to the financial statements under "New Source Review Actions" for additional information.
The Company believes that it complied with applicable laws and the EPA regulations and interpretations in effect at the time the work in question took place. The Clean Air Act authorizes maximum civil penalties of $25,000 to $32,500 per day, per violation at each generating unit, depending on the date of the alleged violation. An adverse outcome in this matter could require substantial capital expenditures that cannot be determined at this time and could possibly require payment of substantial penalties. This could affect future results of operations, cash flows, and possibly financial condition if such costs are not recovered through regulated rates.
clarified the scope of the existing Routine Maintenance, Repair, and Replacement (RMRR) exclusion. A coalition of states and environmental organizations has filed petitions for review of these revisions with the U.S. Court of Appeals for the District of Columbia Circuit. The October 2003 RMRR rules have been stayed by the Court of Appeals pending its review of the rules. In any event, the final regulations must also be adopted by the State of Alabama in order to apply to the Company's facilities.
The effect of these final regulations, related legal challenges, and potential state rulemakings cannot be determined at this time.
Carbon Dioxide Litigation On July 21,2004, attorneys general from eight states, each outside of Southern Company's service territory, and the corporation counsel for New York City filed a complaint in the U.S. District Court for the Southern District of New York against Southern Company and four other electric power companies. A nearly identical complaint was filed by three environmental groups in the same court. The complaints allege that the companies' emissions of carbon dioxide, a greenhouse gas, contribute to global warming, which the plaintiffs assert is a public nuisance. Under common law public and private nuisance theories, the plaintiffs seek a judicial order (1) holding each defendant jointly and severally liable for creating, contributing to, and/or maintaining global warming and (2) requiring each of the defendants to cap its emissions of carbon dioxide and then reduce those emissions by a specified percentage each year for at least a decade. Plaintiffs have not, however, requested that damages be awarded in connection with their claims. Southern Company believes these claims are without merit and notes that the complaint cites no statutory or regulatory basis for the claims. Southern Company and the other defendants have filed motions to dismiss both lawsuits. Southern Company intends to vigorously defend against these claims. While the outcome of these matters cannot be determined at this time, an adverse judgment in either of these actions could result in substantial capital expenditures.
In December 2002 and October 2003, the EPA issued final revisions to its NSR regulations under the Clean Air Act. The December 2002 revisions included changes to the regulatory exclusions and the methods of calculating emissions increases. The October 2003 regulations 9
MNIANAGENIENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2004 Annual Report Environmental Statutes and Regulations The Company's operations are subject to extensive regulation by state and federal environmental agencies under a variety of statutes and regulations governing environmental media, including air, water, and land resources. Compliance with these environmental requirements involves significant capital and operating costs, a major portion of which is expected to be recovered through existing ratemaking provisions. See "FERC and Alabama PSC Matters - Environmental Rate Filing" and Note 3 to the financial statements under "Retail Rate Adjustment Procedures" for additional information.
Environmental costs that are known and estimable at this time are included in capital expenditures discussed under FINANCIAL CONDITION AND LIQUIDITY - "Capital Requirements and Contractual Obligations" herein. There is no assurance, however, that all such costs will, in fact, be recovered.
Compliance with the Clean Air Act and resulting regulations has been and will continue to be a significant focus for the Company. The Title IV acid rain provisions of the Clean Air Act, for example, required significant reductions in sulfur dioxide and nitrogen oxide emissions and resulted in total construction expenditures of approximately $66 million through 2000. Some of these previous expenditures also assisted the Company in complying with nitrogen oxide emission reduction requirements under Title I of the Clean Air Act, which were designed to address one-hour ozone nonattainment problems in Birmingham, Alabama. In December 2000, the Alabama Department of Environmental Management (ADEM) adopted revisions to the state implementation plan for meeting the one-hour ozone standard. These revisions required additional nitrogen oxide emission reductions from May through September of each year at plants in and/or near those nonattainment areas. Two plants in the Birmingham area are currently subject to those requirements, the most recent of which went into effect in 2003. Construction expenditures for compliance with the nitrogen oxide emission reduction requirements totaled approximately $249 million through 2004.
To help attain the one-hour ozone standard, the EPA issued regional nitrogen oxide reduction rules in 1998.
Those rules required 21 states, including Alabama, to reduce and cap nitrogen oxide emissions from power plants and other large industrial sources. Affected sources, including five of the Company's coal-fired plants, were required to comply with these reductions by May 31, 2004. Additional construction expenditures for compliance with these rules are currently estimated at approximately $369 million, of which $169 million remains to be spent. In March 2004, the EPA redesignated the Birmingham, Alabama area from nonattainment to attainment under the one-hour ozone standard.
In July 1997, the EPA revised the national ambient air quality standards for ozone and particulate matter.
These revisions made the standards significantly more stringent and included development of an eight-hour ozone standard, as opposed to the previous one-hour ozone standard. In the subsequent litigation of these standards, the U.S. Supreme Court found the EPA's implementation program for the new eight-hour ozone standard unlawful and remanded it to the EPA for further rulemaking. During 2003, the EPA proposed implementation rules designed to address the court's concerns. On April 30, 2004, the EPA published its eight-hour ozone nonattainment designations and a portion of the rules implementing the new eight-hour ozone standard.
The counties around Birmingham have been designated as nonattainment under the eight-hour ozone standard.
Under the implementation provisions of the new rule, the EPA announced that the one-hour ozone standard will be revoked on June 15, 2005. With respect to the eight-hour nonattainment areas, state implementation plans, including new emission control regulations necessary to bring those areas into attainment, could be required as early as 2007.
These state implementation plans could require reductions in nitrogen oxide emissions from power plants. The impact of the eight-hour designations and the new standard will depend on the development and implementation of Alabama's state implementation plan and therefore cannot be determined at this time.
On December 17, 2004, the EPA issued its final "nonattainment" designations for the fine particulate national ambient air quality standard. Several areas within the Company's service area were included in the EPA's final particulate matter designations. The EPA plans to propose a fine particulate matter implementation rule in 2005 and finalize the implementation rule in 2006. State implementation plans addressing the nonattainment designations may be required by 2008 and could require reductions in sulfur dioxide emissions and further reductions in nitrogen oxide emissions from power plants.
The impact of the fine particulate designations will depend on the development and implementation of Alabama state implementation plans and therefore cannot be determined at this time.
In January 2004, the EPA issued a proposed Clean Air Interstate Rule (CAIR) to address interstate transport of 10
MANAGENIENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2004 Annual Report ozone and fine particles. This proposed rule would require additional year-round sulfur dioxide and nitrogen oxide emission reductions from power plants in the eastern United States in two phases - in 2010 and 2015.
The EPA currently plans to finalize this rule in 2005. If finalized, the rule could modify or supplant other state requirements for attainment of the fine particulate matter standard and the eight-hour ozone standard, as well as other air quality regulations. The impact of this rule on the Company will depend upon the specific requirements of the final rule and cannot be determined at this time.
The Company has developed and maintains an environmental compliance strategy for the installation of additional control technologies and the purchase of emission allowances to assure continued compliance with current sulfur dioxide and nitrogen oxide emission regulations. Additional expenses associated with these regulations are anticipated to be incurred each year to maintain current and future compliance. Because the Company's compliance strategy is impacted by factors such as changes to existing environmental laws and regulations, increases in the cost of emissions allowances, and any change in the Company's fuel mix, future environmental compliance costs cannot be determined at this time.
Further reductions in sulfur dioxide and nitrogen oxides could also be required under the EPA's Regional Haze rules. The Regional Haze rules require states to establish Best Available Retrofit Technology (BART) standards for certain sources that contribute to regional haze and to implement emission reduction requirements that make progress toward remedying current visibility impairment in certain natural areas. The Company has a number of plants that could be subject to these rules. The EPA's Regional Haze program calls for states to submit implementation plans in 2008 that contain emission reduction strategies for implementing BART and for achieving sufficient progress toward the Clean Air Act's visibility improvement goal. In response to litigation, the EPA proposed revised rules in May 2004, which it plans to finalize in April 2005. The impact of these regulations will depend on the promulgation of final rules and implementation of those rules by the states and, therefore, it is not possible to determine the effect of these rules on the Company at this time.
In January 2004, the EPA issued proposed rules regulating mercury emissions from electric utility boilers.
The proposal solicits comments on two possible approaches for the new regulations - a Maximum Achievable Control Technology approach and a cap-and-trade approach. Either approach would require significant reductions in mercury emissions from Company facilities.
The regulations are scheduled to be finalized by March 2005, and compliance could be required as early as 2008.
Because the regulations have not been finalized, the impact on the Company cannot be determined at this time.
Major bills to amend the Clean Air Act to impose more stringent emissions limitations on power plants, including the Bush Administration's Clear Skies Act, have been re-proposed in 2005. The Clear Skies Act is expected to further limit power plant emissions of sulfur dioxide, nitrogen oxides, and mercury and to supplement the proposed CAIR and mercury regulatory programs.
Other proposals to limit emissions of carbon dioxide have also been introduced. The cost impacts of such legislation would depend upon the specific requirements enacted and cannot be determined at this time.
Under the Clean Water Act, the EPA has been developing new rules aimed at reducing impingement and entrainment of fish and fish larvae at power plants' cooling water intake structures. In July 2004, the EPA published final rules that will require biological studies and, perhaps, retrofits to some intake structures at existing power plants. The impact of these new rules will depend on the results of studies and analyses performed as part of the rules' implementation and the actual limits established by the regulatory agencies.
Several major pieces of environmental legislation are periodically considered for reauthorization or amendment by Congress. These include: the Clean Air Act; the Clean Water Act; the Comprehensive Environmental Response, Compensation, and Liability Act; the Resource Conservation and Recovery Act; the Toxic Substances Control Act; the Emergency Planning & Community Right-to-Know Act; and the Endangered Species Act.
Compliance with possible additional federal or state legislation or regulations related to global climate change or other environmental and health concerns could also significantly affect the Company. The impact of any new legislation, changes to existing legislation, or environmental regulations could affect many areas of the Company's operations. The full impact of any such changes cannot, however, be determined at this time.
Global Climate Issues Domestic efforts to limit greenhouse gas emissions have been spurred by international discussions surrounding the Framework Convention on Climate Change -- and specifically the Kyoto Protocol -- which proposes 11
IMlANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2004 Annual Report constraints on the emissions of greenhouse gases for a group of industrialized countries. The Bush Administration has not supported U.S. ratification of the Kyoto Protocol or other mandatory carbon dioxide reduction legislation and, in 2002, announced a goal to reduce the greenhouse gas intensity of the U.S. - the ratio of greenhouse gas emissions to the value of U.S.
economic output -- by 18 percent by 2012. A year later, the Department of Energy (DOE) announced the Climate VISION program to support this goal. Energy-intensive industries, including electricity generation, are the initial focus of this program. Southern Company is leading the development of a voluntary electric utility sector climate change initiative in partnership with the government. The utility sector has pledged to reduce its greenhouse gas emissions rate by 3 to 5 percent over the next decade and, on December 13, 2004, signed a memorandum of understanding with the DOE initiating this program under Climate VISION. Because efforts under this voluntary program are just beginning, the impact of this program on the Company cannot be determined at this time.
Environmental Remediation Reserves The Company must comply with other environmental laws and regulations that cover the handling and disposal of waste and releases of hazardous substances. Under these various laws and regulations, the Company could incur substantial costs to clean up properties. The Company conducts studies to determine the extent of any required cleanup and has recognized in its financial statements the costs to clean up known sites. Amounts for cleanup and ongoing monitoring costs were not material for any year presented. The Company may be liable for some or all required cleanup costs for additional sites that may require environmental remediation. The Company has not incurred any significant cleanup costs to date.
FERC andAlabama PSC Matters Transmission In December 1999, the FERC issued its final rule on Regional Transmission Organizations (RTOs). Since that time, there have been a number of additional proceedings at the FERC designed to encourage further voluntary formation of RTOs or to mandate their formation. However, at the current time, there are no active proceedings that would require the Company to participate in an RTO. Current FERC efforts that may potentially change the regulatory and/or operational structure of transmission include rules related to the standardization of generation interconnection, as well as an inquiry into, among other things, market power by vertically integrated utilities. See "Generation Interconnection Agreements" and "Market-Based Rate Authority" herein for additional information. The final outcome of these proceedings cannot now be determined. However, the Company's financial condition, results of operations and cash flows could be adversely affected by future changes in the federal regulatory or operational structure of transmission.
Generation Interconnection Agreements In July 2003, the FERC issued its final rule on the standardization of generation interconnection agreements and procedures (Order 2003). Order 2003 shifts much of the financial burden of new transmission investment from the generator to the transmission provider. The FERC has indicated that Order 2003, which was effective January 20, 2004, is to be applied prospectively to interconnection agreements. Subsidiaries of Tenaska, Inc., as counterparties to two previously executed interconnection agreements with the Company, have filed complaints at the FERC requesting that the FERC modify the agreements and that the Company refund a total of$1 1 million previously paid for interconnection facilities, with interest. The Company has also received similar requests from other entities totaling $2.5 million. The Company has opposed such relief, and the proceedings are still pending. The impact of Order 2003 and its subsequent rehearings on the Company and the final results of these matters cannot be determined at this time.
Market-Based Rate Authority The Company has authorization from the FERC to sell power to nonaffiliates at market-based prices. Through SCS, as an agent, the Company also has FERC authority to make short-term opportunity sales at market rates.
Specific FERC approval must be obtained with respect to a market-based contract with an affiliate. In November 2001, the FERC modified the test it uses to consider utilities' applications to charge market-based rates and adopted a new test called the Supply Margin Assessment (SMA). The FERC applied the SMA to several utilities, including Southern Company, the retail operating companies, and Southern Power, and found them and others to be "pivotal suppliers" in their retail service territories and ordered the implementation of several mitigation measures. Southern Company and others sought rehearing of the FERC order, and the FERC delayed the implementation of certain mitigation measures. In April 2004, the FERC issued an order that abandoned the SMA test and adopted a new interim analysis for measuring generation market power. This 12
MANAGENIENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2004 Annual Report new interim approach requires utilities to submit a pivotal supplier screen and a wholesale market share screen. If the applicant does not pass both screens, there will be a rebuttable presumption regarding generation market power. The FERC's order also sets forth procedures for rebutting these presumptions and addresses mitigation measures for those entities that are found to have market power. In the absence of specific mitigation measures, the order includes several cost-based mitigation measures that would apply by default. The FERC also initiated a new rulemaking proceeding that, among other things, will adopt a final methodology for assessing generation market power.
In July 2004, the FERC denied Southern Company's request for rehearing, along with a number of others, and reaffirmed the interim tests that it adopted in April. In August 2004, Southern Company submitted a filing to the FERC that included results showing that Southern Company passed the pivotal supplier screen for all markets and the wholesale market share screen for all markets except the Southern Company retail service territory. Southern Company also submitted other analyses to demonstrate that it lacks generation market power. On December 17, 2004, the FERC initiated a proceeding to assess Southern Company's generation dominance within its retail service territory. The ability to charge market-based rates in other markets is not at issue. As directed by this order, on February 15, 2005, Southern Company submitted additional information related to generation dominance in its retail service territory. Any new market-based rate transactions in Southern Company's retail service territory entered into after February 27, 2005 will be subject to refund to the level of the default cost-based rates, pending the outcome of the proceeding. Southern Company, along with other utilities, has also filed an appeal of the FERC's April and July 2004 orders with the U.S. Court of Appeals for the District of Columbia Circuit. The FERC has asked the court to dismiss the appeal on the grounds that it is premature.
In the event that the FERC's default mitigation measures are ultimately applied, the Company may be required to charge cost-based rates for certain wholesale sales in Southern Company's retail service territory, which may be lower than negotiated market-based rates. The final outcome of this matter will depend on the form in which the final methodology for assessing generation market power and mitigation rules may be ultimately adopted and cannot be determined at this time.
Hydro Relicensing In 2002, the Company initiated the relicensing process for the Company's seven hydroelectric projects on the Coosa River (Weiss, Henry, Logan Martin, Lay, Mitchell, Jordan, and Bouldin) and the Smith and Bankhead projects on the Warrior River. The FERC licenses for all of these nine projects expire in 2007. Upon or after the expiration of each license, the United States Government, by act of Congress, may take over the project or the FERC may relicense the project either to the original licensee or to a new licensee. The FERC may grant relicenses subject to certain requirements that could result in additional costs to the Company. The final outcome of this matter cannot be determined at this time.
Nuclear Relicensing The Company filed an application with the Nuclear Regulatory Commission (NRC) in September 2003 to extend the operating license for Plant Farley for an additional 20 years. The NRC is expected to rule on the application by July 2005. If the NRC approves the extension, the Company's annual decommissioning expense could decrease, subject to Alabama PSC approval. See Note I to the financial statements under "Nuclear Decommissioning" for additional information.
Environmental Rate Filing On October 5, 2004, the Alabama PSC approved a specific rate mechanism for the recovery of the Company's retail costs associated with environmental laws, regulations, or other such mandates. The rate mechanism began operation in January 2005 and provides for the recovery of these costs pursuant to a factor that will be calculated annually. Environmental costs to be recovered include operation and maintenance expenses, depreciation and a return on invested capital. Retail rates have increased 1 percent in 2005, which should yield an annual recovery of approximately $33 million, and are expected to increase an additional I percent in 2006. In conjunction with the Alabama PSC's approval, the Company agreed to a moratorium until March 2007 on any retail rate increase under the previously approved Rate Stabilization and Equalization plan (RSE). Any increase in March 2007 would be based upon the earned return on retail common equity at December 31, 2006. See Note 3 to the financial statements under "Retail Rate Adjustment Procedures" for further information on RSE.
13
iMANAGENIENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2004 Annual Report Retail Rate Adjustments The Company's retail rates, approved by the Alabama PSC, also provide for adjustments to recognize the placing of new generating facilities into retail service and the recovery of retail costs associated with certificated PPAs under Rate Certificated New Plant (CNP). Effective July 2003, the Company's retail rates were adjusted by approximately 2.6% under Rate CNP as a result of two new certificated PPAs that began in June 2003. An additional increase of $25 million annually was effective July 2004 under Rate CNP for new certificated PPAs. In April 2005, an adjustment to Rate CNP is expected to decrease retail rates by approximately 0.5 percent, or $18.5 million annually. See Note 3 to the financial statements under "Retail Rate Adjustment Procedures" for additional information.
Retail Fuel Cost Recovery The Company has established fuel cost recovery rates approved by the Alabama PSC. In recent months, the Company has experienced higher than expected fuel costs for coal and gas. Those higher fuel costs have increased the under recovered fuel costs included in the balance sheets. In April 2005, the retail energy clause recovery factor is scheduled to increase from its current level. The Company will continue to monitor the under recovered fuel cost balance to determine if an additional adjustment to billing rates should be requested from the Alabama PSC.
Natural Disaster Cost Recovery The Company maintains a reserve for operation and maintenance expense to cover the cost of damages from major storms to its transmission and distribution lines and the cost of uninsured damages to its generation facilities and other property. On September 15 and 16, 2004, Hurricane Ivan hit the Gulf Coast of Florida and Alabama and continued north through the state of Alabama, causing substantial damage in the service territory of the Company. Approximately 826,000 of the Company's 1,370,000 customer accounts were without electrical service immediately after the hurricane. Almost 95% of those without power had service restored within one week, and two weeks after the storm, power had been restored to all who could receive service.
The operation and maintenance expenses associated with repairing the damage to the Company's facilities and restoring service to customers as a result of Hurricane Ivan were S57.8 million for 2004. The balance in the Company's natural disaster reserve prior to the storm was $14.6 million. On October 19,2004, the Company received approval from the Alabama PSC to record its hurricane related operation and maintenance expenses in its natural disaster reserve, thereby deferring the regulatory asset for recovery in future periods. The Company is allowed to accrue
$250 thousand per month until a maximum accumulated provision of $32 million is attained.
Higher accruals to restore the reserve to its authorized level are allowed whenever the balance in the reserve declines below $22.4 million. During 2004, the Company accrued $9.9 million, including an additional amount of $6.9 million, to the reserve and at December 31, 2004 the regulatory asset totaled S37.7 million.
In February 2005, the Company requested and received Alabama PSC approval of an accounting order that allows the Company to immediately return certain regulatory liabilities to the retail customers. The order also allows the Company to simultaneously recover from customers an accrual of approximately $45 million to offset the costs of Hurricane Ivan and restore the natural disaster reserve. The combined effects of this order will have no impact on the Company's net income in 2005. See Notes 1 and 3 to the financial statements under "Natural Disaster Reserve" and "Natural Disaster Cost Recovery," respectively, for additional information on these reserves.
Income Tax Matters American Jobs Creation Act of2004 On October 22, 2004, President Bush signed the American Jobs Creation Act of 2004 (Jobs Act) into law. The Jobs Act includes a provision that allows a generation tax deduction for utilities. The Company is currently assessing the impact of the Jobs Act, including this deduction, as well as the related regulatory treatment, on its taxable income. However, the Company currently does not expect the Jobs Act to have a material impact on its financial statements.
Other Matters In accordance with Financial Accounting Standards Board (FASB) Statement No. 87, Employers' Accounting for Pensions, the Company recorded non-cash pension income, before tax, of approximately $36 million, $52 million, and $56 million in 2004, 2003, and 2002, respectively. Future pension income is dependent on several factors including trust earnings and changes to the pension plan. The decline in pension income is expected to continue, but should not become a pension expense in 14
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2004 Annual Report the foreseeable future. Postretirement benefit costs for the Company were $22 million, $23 million, and $23 million in 2004, 2003, and 2002, respectively, and are expected to trend upward. A portion of pension income and postretirement benefit costs is capitalized based on construction-related labor charges. Pension and postretirement benefit costs are a component of the regulated rates and generally do not have a long-term effect on net income. For more information regarding pension and postretirement benefits, see Note 2 to the financial statements.
The Company is involved in various other matters being litigated and regulatory matters that could affect future earnings. See Note 3 to the financial statements for information regarding material issues.
ACCOUNTING POLICIES Application of Critical Accounting Policies and Estimates The Company prepares its financial statements in accordance with accounting principles generally accepted in the United States. Significant accounting policies are described in Note I to the financial statements. In the application of these policies, certain estimates are made that may have a material impact on the Company's results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements.
Southern Company senior management has discussed the development and selection of the critical accounting policies and estimates described below with the Audit Committee of Southern Company's Board of Directors.
Electric Utility Regulation The Company is subject to retail regulation by the Alabama PSC and wholesale regulation by the FERC.
These regulatory agencies set the rates the Company is permitted to charge customers based on allowable costs. As a result, the Company applies FASB Statement No. 71, Accounting for the Effects of Certain Types of Regulation, which requires the financial statements to reflect the effects of rate regulation.
Through the ratemaking process, the regulators may require the inclusion of costs or revenues in periods different than when they would be recognized by a non-regulated company. This treatment may result in the deferral of expenses and the recording of related regulatory assets based on anticipated future recovery through rates or the deferral of gains or creation of liabilities and the recording of related regulatory liabilities. The application of Statement No. 71 has a further effect on the Company's financial statements as a result of the estimates of allowable costs used in the ratemaking process. These estimates may differ from those actually incurred by the Company; therefore, the accounting estimates inherent in specific costs such as depreciation, nuclear decommissioning, and pension and postretirement benefits have less of a direct impact on the Company's results of operations than they would on a non-regulated company.
As reflected in Note I to the financial statements under "Regulatory Assets and Liabilities," significant regulatory assets and liabilities have been recorded.
Management reviews the ultimate recoverability of these regulatory assets and liabilities based on applicable regulatory guidelines. However, adverse legislative, judicial, or regulatory actions could materially impact the amounts of such regulatory assets and liabilities and could adversely impact the Company's financial statements.
Contingent Obligations The Company is subject to a number of federal and state laws and regulations, as well as other factors and conditions that potentially subject it to environmental, litigation, income tax, and other risks. See "FUTURE EARNINGS POTENTIAL" herein and Note 3 to the financial statements for more information regarding certain of these contingencies. The Company periodically evaluates its exposure to such risks and records reserves for those matters where a loss is considered probable and reasonably estimable in accordance with generally accepted accounting principles. The adequacy of reserves can be significantly affected by external events or conditions that can be unpredictable; thus, the ultimate outcome of such matters could materially affect the Company's financial statements. These events or conditions include the following:
- Changes in existing state or federal regulation by governmental authorities having jurisdiction over air quality, water quality, control of toxic substances, hazardous and solid wastes, and other environmental matters.
- Changes in existing income tax regulations or changes in Internal Revenue Service interpretations of existing regulations.
- Identification of additional sites that require environmental remediation or the filing of other complaints in which the Company may be asserted to be a potentially responsible party.
15
NIANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2004 Annual Report
- Identification and evaluation of other potential lawsuits or complaints in which the Company may be named as a defendant.
- Resolution or progression of existing matters through the legislative process, the court systems, or the EPA.
Un billed Revenues Revenues related to the sale of electricity are recorded when electricity is delivered to customers. However, the determination of KWH sales to individual customers is based on the reading of their meters, which is performed on a systematic basis throughout the month. At the end of each month, amounts of electricity delivered to customers, but not yet metered and billed, are estimated.
Components of the unbilled revenue estimates include total KWH territorial supply, total KWH billed, estimated total electricity lost in delivery, and customer usage.
These components can fluctuate as a result of a number of factors including weather, generation patterns, power delivery volume, and other operational constraints. These factors can be unpredictable and can vary from historical trends. As a result, the overall estimate of unbilled revenues could be significantly affected, which could have a material impact on the Company's results of operations.
New Accounting Standards On March 31, 2004, the Company prospectively adopted FASB Interpretation No. 46R, Consolidation of Variable Interest Entities, which requires the primary beneficiary of a variable interest entity to consolidate the related assets and liabilities. The adoption of FASB Interpretation No. 46R had no impact on the Company's net income. However, as a result of the adoption, the Company deconsolidated certain wholly-owned trusts established to issue preferred securities since the Company does not meet the definition of primary beneficiary established by FASB Interpretation No. 46R. See Note I to the financial statements under "Variable Interest Entities" for additional information.
In the third quarter 2004, the Company prospectively adopted FASB Staff Position (FSP) 106-2, Accounting and Disclosure Requirements related to the Medicare Prescription Drug, Improvement, and Modernization Act of 2003 (Medicare Act). The Medicare Act provides a 28 percent prescription drug subsidy for Medicare eligible retirees. FSP 106-2 requires recognition of the impacts of the Medicare Act in the accumulated postretirement benefit obligation (APBO) and future cost of service for postretirement medical plans. The effect of the subsidy reduced the Company's expenses for the six months ended December 31, 2004 by approximately $3.2 million and is expected to have a similar impact on future expenses.
The subsidy's impact on the postretirement medical plan APBO was a reduction of approximately $59.8 million. However, the ultimate impact on future periods is subject to final interpretation of the federal regulations which were published on January 21, 2005.
See Note 2 to the financial statements under "Postretirement Benefits" for additional information.
FASB Statement No. 123R, Share-Based Payment was issued in December 2004. This statement requires that compensation cost relating to share-based payment transactions be recognized in financial statements. That cost will be measured based on the grant date fair value of the equity or liability instruments issued. For the Company, this statement is effective beginning on July 1, 2005. Although the compensation expense calculation required under the revised statement differs slightly, the impact on the Company's financial statements are expected to be similar to the pro forma disclosures included in Note I to the financial statements under "Stock Options."
See FUTURE EARNINGS POTENTIAL -
"Income Tax Matters -- American Jobs Creation Act of 2004" herein for information regarding the adoption of new tax legislation. In December 2004, the FASB issued FSP 109-1, Application of FASB Statement No.
109, Accounting for Income Taxes, to the Tax Deduction on Qualified Production Activities provided by the American Jobs Creation Act of 2004, which requires that the generation deduction be accounted for as a special tax deduction rather than as a tax rate reduction. The Company is currently assessing the Jobs Act and this pronouncement, as well as the related regulatory treatment, but currently does not expect a material impact on the Company's financial statements.
FINANCIAL CONDITION AND LIQUIDITY Overview The Company's financial condition continued to be strong at December 31, 2004. Net cash flow from operating activities totaled $1.0 billion, SI.l billion, and
$973 million for 2004, 2003, and 2002, respectively. The
$107 million decrease for 2004 in operating activities primarily relates to an increase in under recovered fuel cost and storm damage costs related to Hurricane Ivan.
These increases were partially offset by the deferral of income tax liabilities arising from accelerated depreciation 16
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2004 Annual Report deductions. Fuel costs are recoverable in future periods and are reflected on the balance sheets as under recovered regulatory clause revenues. The $145 million increase from 2002 to 2003 resulted from the deferral of income tax liabilities arising from accelerated depreciation deductions offset by the settlement of interest rate hedges.
Significant balance sheet changes include the $478 million increase in long-term debt for 2004 primarily due to the replacement of debt due within one year with long-term debt, and an increase of $412 million in gross plant.
The Company's ratio of common equity to total capitalization -- including short-term debt -- was 42.6 percent in 2004, 43.3 percent in 2003, and 42.6 percent in 2002. See Note 6 to the financial statements for additional information.
Sources of Capital The Company plans to obtain the funds required for construction and other purposes from sources similar to those used in the past, which were primarily from operating cash flows. However, the type and timing of any financings -- if needed -- will depend on market conditions and regulatory approval. In recent years, financings primarily have utilized unsecured debt, preferred stock, and preferred securities.
Security issuances are subject to regulatory approval by the Alabama PSC. Additionally, with respect to the public offering of securities, the Company must file registration statements with the Securities and Exchange Commission (SEC) under the Securities Act of 1933, as amended (1933 Act). The amounts of securities authorized by the Alabama PSC, as well as the amounts registered under the 1933 Act, are continuously monitored and appropriate filings are made to ensure flexibility in the capital markets.
The Company obtains financing separately without credit support from any affiliate. The Southern Company system does not maintain a centralized cash or money pool. Therefore, funds of the Company are not commingled with funds of any other company. In accordance with the Public Utility Holding Company Act of 1935, as amended (PUHCA), most loans between affiliated companies must be approved in advance by the SEC.
To meet short-term cash needs and contingencies, the Company has various internal and external sources of liquidity. At the beginning of 2005, the Company had approximately $84 million of cash and cash equivalents and
$868 million of unused credit arrangements with banks. In addition, the Company has substantial cash flow from operating activities and access to the capital markets, including commercial paper programs, to meet liquidity needs.
The Company maintains committed lines of credit in the amount of $868 million of which $643 million will expire at various times during 2005. $225 million of the credit facilities expiring in 2005 allow for the execution of term loans for an additional two-year period, and $245 million allow for the execution of one-year term loans.
See Note 6 to the financial statements under "Bank Credit Arrangements" for additional information.
The Company may also meet short-term cash needs through a Southern Company subsidiary organized to issue and sell commercial paper and extendible commercial notes at the request and for the benefit of the Company and the other Southern Company retail operating companies. Proceeds from such issuances for the benefit of the Company are loaned directly to the Company and are not commingled with proceeds from such issuances for the benefit of any other retail operating company. The obligations of each company under these arrangements are several and there is no cross affiliate credit support.
At December 31, 2004, the Company had no commercial paper or extendible commercial notes outstanding.
Financing Activities During 2004, the Company issued $900 million of long-term debt and $100 million of preferred stock. In addition, the Company issued I million new shares of common stock to Southern Company at $40.00 a share and realized proceeds of $40 million. The proceeds of these issues were used to redeem or repay at maturity long-term debt, to repay short-term indebtedness, and for other general corporate purposes.
The Company's current liabilities frequently exceed current assets because of the continued use of short-term debt as a funding source to meet cash needs which can fluctuate significantly due to the seasonality of the business.
17
NIANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2004 Annual Report Composite financing rates for long-term debt, preferred stock, and preferred securities for the years 2002 through 2004, as of year-end, were as follows:
2004 2003 2002 Long-term debt interest rate 4.14%
4.42%
5.05%
Preferred securities distribution rate 5.25 5.25 5.25 Preferred stock dividend rate 5.14 5.10 5.17 Credit Rating Risk The Company does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade.
However, the Company is party to certain derivative agreements that could require collateral and/or accelerated payment in the event of a credit rating change to below investment grade. These agreements are primarily for natural gas price and interest rate risk management activities. At December 31, 2004, the Company's maximum potential exposure to these contracts was $9.8 million.
Market Price Risk Due to cost-based rate regulations, the Company has limited exposure to market volatility in interest rates, commodity fuel prices, and prices of electricity. To manage the volatility attributable to these exposures, the Company nets the exposures to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to the Company's policies in areas such as counterparty exposure and risk management practices. Company policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques including, but not limited to, market valuation, value at risk, stress testing, and sensitivity analysis.
To mitigate exposure to interest rates, the Company has entered into interest rate swaps that have been designated as hedges. The weighted average interest rate on outstanding variable long-term debt that has not been hedged at January 1, 2005 was 2.57 percent. If the Company sustained a 100 basis point change in interest rates for all unhedged variable rate long-term debt, the change would affect annualized interest expense by approximately S2.5 million at January 1, 2005. The Company is not aware of any facts or circumstances that would significantly affect such exposures in the near term.
For further information, see Notes I and 6 to the financial statements under "Financial Instruments."
To mitigate residual risks relative to movements in electricity prices, the Company enters into fixed-price contracts for the purchase and sale of electricity through the wholesale electricity market and, to a lesser extent, into similar contracts for gas purchases. The Company has implemented fuel hedging programs at the instruction of the Alabama PSC.
In addition, the Company's Rate ECR allows the recovery of specific costs associated with the sales of natural gas that become necessary due to operating considerations at the Company's electric generating facilities. Rate ECR also allows recovery of the cost of financial instruments used for hedging market price risk up to 75 percent of the budgeted annual amount of natural gas purchases. The Company may not engage in natural gas hedging activities that extend beyond a rolling 42-month window. Also, the premiums paid for natural gas financial options may not exceed 5 percent of the Company's natural gas budget for that year.
At December 31, 2004, exposure from these activities was not material to the Company's financial position, results of operations, or cash flows. The fair value changes in energy related derivative contracts and year-end valuations were as follows at December 31:
Changes in Fair Value 2004 2003 (in thousands)
Contracts beginning of year S 6,413
$ 21,402 Contracts realized or settled (26,384)
(38,809)
New contracts at inception Changes in valuation techniques Current period changes(a) 23,988 23,820 Contracts end of year
$ 4,017
$ 6,413 (a) Current period changes also include the changes in fair value of new contracts entered into during the period.
Source of 2004 Year-End Valuation Prices Total Maturity Fair Value 2005 2006-2007 (in thousands)
Actively quoted
$3,985
$2,917
$1,068 External sources 32 32 Models and other methods Contracts end of Year
$4,017
$2,949
$1,068 18
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2004 Annual Report Unrealized gains and losses from mark to market adjustments on derivative contracts related to the Company's fuel hedging programs are recorded as regulatory assets and liabilities. Realized gains and losses from these programs are included in fuel expense and are recovered through the Company's fuel cost recovery clause. Gains and losses on derivative contracts that are not designated as hedges are recognized in the income statement as incurred. At December 31, 2004, the fair value of derivative energy contracts was reflected in the financial statements as follows:
Amounts (in thousands)
Regulatory liabilities, net
$3,978 Other comprehensive income Net income 39 Total fair value
$4,017 Unrealized pre-tax gains (losses) on energy contracts recognized in income in 2004 and 2003 were not material.
For 2002, pre-tax losses of $2.0 million were recognized in income. The Company is exposed to market price risk in the event of nonperformance by counterparties to the derivative energy contracts. The Company's policy is to enter into agreements with counterparties that have investment grade credit ratings by Moody's and Standard
& Poor's or with counterparties who have posted collateral to cover potential credit exposure. Therefore, the Company does not anticipate market risk exposure from nonperformance by the counterparties. For additional information, see Notes I and 6 to the financial statements under "Financial Instruments."
Capital Requirements and Contractual Obligations The construction program of the Company is currently estimated to be $902 million for 2005, $921 million for 2006, and $1.0 billion for 2007. Over the next three years, the Company estimates spending $913 million on environmental related additions (including $276 million on selective catalytic reduction facilities), $238 million on Plant Farley (including $177 million for nuclear fuel),
$767 million on distribution facilities, and $411 million on transmission additions. See Note 7 to the financial statements under "Construction Program" for additional details.
Actual construction costs may vary from this estimate because of changes in such factors as: business conditions; environmental regulations; nuclear plant regulations; FERC rules and transmission regulations; load projections; the cost and efficiency of construction labor, equipment, and materials; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered.
In addition to the funds required for the Company's construction program, approximately $1.4 billion will be required by the end of 2007 for maturities of long-term debt. The Company plans to continue, when economically feasible, to retire higher cost securities and replace these obligations with lower-cost capital if market conditions permit.
As a result of requirements by the NRC, the Company has established external trust funds for the purpose of funding nuclear decommissioning costs. Annual provisions for nuclear decommissioning are based on an annuity method as approved by the Alabama PSC. The amount expensed in 2004 was $18 million. For additional information, see Note I to the financial statements under "Nuclear Decommissioning." Additionally, as discussed in Note I to the financial statements under "Fuel Costs,"
in 1993 the DOE implemented a special assessment over a 15-year period on utilities with nuclear plants to be used for the decontamination and decommissioning of its nuclear fuel enrichment facilities.
The Company has also established an external trust fund for postretirement benefits as ordered by the Alabama PSC. The cumulative effect of funding these items over a long period will diminish internally funded capital for other purposes and may require the Company to seek capital from other sources. For additional information, see Note 2 to the financial statements under "Postretirement Benefits."
Other funding requirements related to obligations associated with scheduled maturities of long-term debt and preferred securities, as well as the related interest, preferred stock dividends, leases, and other purchase commitments, are as follows. See Notes 1, 6, and 7 to the financial statements for additional information.
19
IWANAGENIENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2004 Annual Report Contractual Obligations 2006-2008-After 2005 2007 2009 2009 Total (in millions)
Long-term debt(a) --
Principal
$ 225.0
$1,215.0
$ 660.0 S2,294.4 S 4,394.4 Interest 185.2 327.3 243.0 1,924.7 2,680.2 Preferred stock dividends(b) 23.6 47.2 47.2 118.0 Operating leases 29.1 35.3 19.0 34.6 118.0 Purchase commnitments(') --
Capital(')
902.5 1,938.4 2,840.9 Coal and nuclear fuel 907.0 1,517.0 356.0 97.0 2,877.0 Natural gas(')
249.0 309.0 52.0 108.0 718.0 Purchased power 87.0 175.0 179.0 38.0 479.0 Long-term service agreements 17.2 35.8 37.3 103.1 193.4 Trusts --
Nuclear decommissioning 20.3 40.6 40.6 192.1 293.6 Postretirement benefits(')
25.3 51.6 76.9 DOE assessments 4.4 4.5 8.9 Total S2,675.6
$5,696.7
$1,634.1 S4,791.9
$14,798.3 (a)
All amounts are reflected based on final maturity dates. The Company plans to continue to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit. Variable rate interest obligations are estimated based on rates as of January 1, 2005, as reflected in the statements of capitalization.
(b)
Preferred stock does not mature; therefore, amounts are provided for the next five years only.
(c)
The Company generally does not enter into non-cancelable commitments for other operation and maintenance expenditures. Total other operation and maintenance expenses for the last three years were S947 million, $921 million, and S854 million, respectively.
(d)
The Company forecasts capital expenditures over a three-year period. Amounts represent current estimates of total expenditures excluding those amounts related to contractual purchase commitments for uranium and nuclear fuel conversion, enrichment, and fabrication services. At December 31, 2004, significant purchase commitments were outstanding in connection with the construction program.
(e)
Natural gas purchase commitments are based on various indices at the time of delivery. Amounts reflected have been estimated based on the New York Mercantile Exchange future prices at December 31, 2004.
(f)
The Company forecasts postretirement trust contributions over a three-year period. No contributions related to the Company's pension trust are currently expected during this period. See Note 2 to the financial statements for additional information related to the pension and postretirement plans, including estimated benefit payments. Certain benefit payments will be made through the related trusts. Other benefit payments will be made from the Company's corporate assets.
20
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2004 Annual Report Cautionary Statement Regarding Forward-Looking Statements The Company's 2004 Annual Report contains forward-looking statements. Forward-looking statements include, among other things, statements concerning retail sales growth and retail rates, storm damage cost recovery, environmental regulations and expenditures, the Company's projections for postretirement benefit trust contributions, and estimated construction and other expenditures. In some cases, forward-looking statements can be identified by terminology such as "may," "will," "could," "should," "expects," "plans," "anticipates," "believes," "estimates,"
"projects," "predicts," "potential," or "continue" or the negative of these terms or other similar terminology. There are various factors that could cause actual results to differ materially from those suggested by the forward-looking statements; accordingly, there can be no assurance that such indicated results will be realized. These factors include:
- the impact of recent and future federal and state regulatory change, including legislative and regulatory initiatives regarding deregulation and restructuring of the electric utility industry, and also changes in environmental, tax, and other laws and regulations to which the Company is subject, as wvell as changes in application of existing laws and regulations;
- current and future litigation, regulatory investigations, proceedings or inquiries, including the pending EPA civil action against the Company;
- the effects, extent, and timing of the entry of additional competition in the markets in which the Company operates;
- variations in demand for electricity and gas, including those relating to weather, the general economy and population and business growth (and declines);
- available sources and costs of fuels;
- ability to control costs;
- investment performance of the Company's employee benefit plans;
- advances in technology;
- state and federal rate regulations and the impact of pending and future rate cases and negotiations;
- internal restructuring or other restructuring options that may be pursued;
- potential business strategies, including acquisitions or dispositions of assets or businesses, which cannot be assured to be completed or beneficial to the Company;
- the ability of counterparties of the Company to make payments as and when due;
- the ability to obtain new short-and long-term contracts with neighboring utilities;
- the direct or indirect effect on the Company's business resulting from terrorist incidents and the threat of terrorist incidents;
- interest rate fluctuations and financial market conditions and the results of financing efforts, including the Company's credit ratings;
- the ability of the Company to obtain additional generating capacity at competitive prices;
- catastrophic events such as fires, earthquakes, explosions, floods, hurricanes, or other similar occurrences;
- the direct or indirect effects on the Company's business resulting from incidents similar to the August 2003 power outage in the Northeast;
- the effect of accounting pronouncements issued periodically by standard-setting bodies; and
- other factors discussed elsewhere herein and in other reports (including the Form 1 0-K) filed by the Company from time to time by the Company with the SEC.
The Company expressly disclaims any obligation to update any forward-looking statements.
21
STATEMNENTS OF INCOIME For the Years Ended December31, 2004, 2003, and 2002 Alabama Power Company 2004 Annual Report 2004 2003 2002 (in thousands)
Operating Revenues:
Retail sales
$3,292,828
$3,051,463
$2,951,217 Sales for resale --
Non-affiliates 483,839 487,456 474,291 Affiliates 308,312 277,287 188,163 Other revenues 151,012 143,955 96,862 Total operating revenues 4,235,991 3,960,161 3,710,533 Operating Expenses:
Fuel 1,186,472 1,067,821 969,521 Purchased power --
Non-affiliates 186,187 110,885 90,998 Affiliates 226,697 204,353 158,121 Other operations 634,030 611,418 574,979 Maintenance 313,407 309,451 279,406 Depreciation and amortization 425,906 412,919 398,428 Taxes other than income taxes 242,809 228,414 216,919 Total operating expenses 3,215,508 2,945,261 2,688,372 Operating Income 1,020,483 1,014,900 1,022,161 Other Income and (Expense):
Allowance for equity funds used during construction Interest income Interest expense, net of amounts capitalized Interest expense to affiliate trusts Distributions on mandatorily redeemable preferred securities Other income (expense), net Total other income and (expense)
Earnings Before Income Taxes Income taxes Net Income Dividends on Preferred Stock Net Income After Dividends on Preferred Stock The accompanying notes are an integral part of these financial statements.
16,141 15,677 (193,590)
(16,191)
(24,728)
(202,691) 817,792 313,024 504,768 23,597 S 481.171 12,594 15,220 (214,302)
(15,255)
(31,702)
(233,445) 781,455 290,378 491,077 18,267 S 472.810 11,168 13,991 (225,706)
(24,599)
(28,785)
(253,931) 768,230 292,436 475,794 14,439 S 461.355 22
STATEMENTS OF CASH FLOWS For the Years Ended December31, 2004, 2003, and 2002 Alabama Power Company 2004 Annual Report 2004 2003 2002 (in thousands)
Operating Activities:
Net income
$504,768
$ 491,077
$ 475,794 Adjustments to reconcile net income to net cash provided from operating activities --
Depreciation and amortization 497,010 487,370 442,660 Deferred income taxes and investment tax credits, net 252,858 153,154 48,828 Deferred revenues (11,510)
(17,932)
(8,099)
Allowance for equity funds used during construction (16,141)
(12,594)
(11,168)
Pension, postretirement, and other employee benefits (29,362)
(38,953)
(34,977)
Tax benefit of stock options 10,672 8,680 6,670 Other, net 10,817 6,292 19,271 Changes in certain current assets and liabilities -
Receivables, net (144,256)
(13,488) 33,074 Fossil fuel stock 30,130 (13,251) 25,535 Materials and supplies (26,229)
(4,651) 3,728 Other current assets 19,131 (953) 1,479 Accounts payable (12,778) 77,128 (1,034)
Accrued taxes (24,568)
(33,507)
(40,922)
Accrued compensation (7,041) 664 17,122 Other current liabilities (42,544) 29,058 (4,798)
Net cash provided from operating activities 1,010,957 1,118,094 973,163 Investing Activities:
Gross property additions (797,014)
(661,154)
(645,262)
Cost of removal net of salvage (37,369)
(35,440)
(32,111)
Other 11,575 (1,169) 5,017 Net cash used for investing activities (822,808)
(697,763)
(672,356)
Financing Activities:
Increase (decrease) in notes payable, net (36,991) 26,994 Proceeds --
Senior notes 900,000 1,415,000 975,000 Mandatorily redeemable preferred securities 300,000 Preferred stock 100,000 125,000 Common stock 40,000 50,000 Capital contributions from parent company 17,541 17,826 43,118 Redemptions --
First mortgage bonds (350,000)
Senior notes (725,000)
(1,507,000)
(415,602)
Other long-term debt (1,445)
(943)
(883)
Mandatorily redeemable preferred securities (347,000)
Preferred stock (70,000)
Payment of preferred stock dividends (23,639)
(18,181)
(14,176)
Payment of common stock dividends (437,300)
(430,200)
(431,000)
Other (16,597)
(14,775)
(30,329)
Net cash used for financing activities (146,440)
(400,264)
(313,878)
Net Change In Cash and Cash Equivalents 41,709 20,067 (13,071)
Cash and Cash Equivalents at Beginning of Period 42,752 22,685 35,756 Cash and Cash Equivalents at End of Period 84,461 42,752 22,685 Supplemental Cash Flow Information:
Cash paid during the period for --
Interest (net of $6,832, $6,367, and $6,738 capitalized, respectively)
S188,556
$185,272
$230,102 Income taxes (net of refunds) 69,068 161,004 269,043 The accompanying notes are an integral part of these financial statements.
23
BALANCE SHEETS At December 31, 2004 and 2003 Alabama Power Company 2004 Annual Report Assets 2004 2003 (in thousands)
Current Assets:
Cash and cash equivalents 84,461 S
42,752 Receivables --
Customer accounts receivable 235,221 223,865 Unbilled revenues 96,486 95,953 Under recovered regulatory clause revenues 119,773 16,697 Other accounts and notes receivable 52,145 53,547 Affiliated companies 61,149 48,876 Accumulated provision for uncollectible accounts (5,404)
(4,756)
Fossil fuel stock, at average cost 57,787 86,993 Vacation pay 36,494 35,530 Materials and supplies, at average cost 237,919 211,690 Prepaid expenses 61,896 78,409 Other 11,269 19,454 Total current assets 1,049,196 909,010 Property, Plant, and Equipment:
In service 14,636,168 14,224,117 Less accumulated provision for depreciation 5,097,930 4,907,549 9,538,238 9,316,568 Nuclear fuel, at amortized cost 93,388 93,611 Construction work in progress 470,844 321,316 Total property, plant, and equipment 10,102,470 9,731,495 Other Property and Investments:
Equity investments in unconsolidated subsidiaries 45,455 47,811 Nuclear decommissioning trusts, at fair value 445,634 384,574 Other 44,322 23,708 Total other property and investments 535,411 456,093 Deferred Charges and Other Assets:
Deferred charges related to income taxes 316,528 321,077 Prepaid pension costs 489,193 446,256 Unamortized debt issuance expense 28,392 23,457 Unamortized loss on reacquired debt 109,403 110,946 Other regulatory assets 46,603 13,092 Other 106,263 91,370 Total deferred charges and other assets 1,096,382 1,006,198 Total Assets S12,783,459
$12,102,796 The accompanying notes are an integral part of these financial statements.
24
BALANCE SHEETS At December 31, 2004 and 2003 Alabama Power Company 2004 Annual Report Liabilities and Stockholder's Equity Current Liabilities:
Securities due within one year Accounts payable --
Affiliated Other Customer deposits Accrued taxes --
Income taxes Other Accrued interest Accrued vacation pay Accrued compensation Other Total current liabilities Long-term Debt (See accompanying statements)
Long-term Debt Payable to Affiliated Trusts (See accompanying statements)
Mandatorily Redeemable Preferred Securities (See accompanying statements)
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes Deferred credits related to income taxes Accumulated deferred investment tax credits Employee benefit obligations Deferred capacity revenues Asset retirement obligations Asset retirement obligation regulatory liability Other cost of removal obligations Miscellaneous regulatory liabilities Other Total deferred credits and other liabilities Total Liabilities Cumulative Preferred Stock (See accompanying statements)
Common Stockholder's Equity (See accompanying statements)
Total Liabilities and Stockholder's Equitv Commitments and Contingent Matters (See notes)
The accompanying notes are an integral part of these financial statements.
2004 2003 (in thousands)
S 225,005 526,019 141,096 141,940 198,834 162,314 49,598 47,507 28,498 3,679 29,688 22,274 40,029 46,489 36,494 35,530 76,858 75,726 26,365 34,407 852,465 3,855,257 309,279 1,095,885 3,377,148 300.000 1,885,120 148,395 205,353 194,837 25,056 383,621 159,230 597,147 55,459 36,989 3,691,207 8,708,208 465,047 3,610,204
$12.783459 1,684,741 162,168 216,309 174,036 36,567 358,759 127,346 572,816 86,323 37,526 3,456,591 8,229,624 372,512 3,500,660
$12,102.796
=
=
- -- I 25
STATEMENTS OF CAPITALIZATION At December 31, 2004 and 2003 Alabama Power Company 2004 Annual Report 2004 2003 2004 2003 (in thousands)
(percent of total)
Long-Term Debt:
Long-term notes payable --
4.875% to 7.125% due 2004
$ 525,000 5.49% due November I, 2005 225,000 225,000 2.65% to 2.80% due 2006 520,000 520,000 Floating rate (2.09% at 1/1/05) due 2006 195,000 195,000 3.50% to 7.125% due 2007 500,000 200,000 3.125% to 5.375% due 2008 410,000 410,000 Floating rate (2.57% at 1/1/05) due 2009 250,000 4.70% to 6.75% due 2010-2039 1,425,000 1,275,000 Total long-term notes payable 3,525,000 3,350,000 Other long-term debt --
Pollution control revenue bonds --
Collateralized:
5.50% due 2024 24,400 24,400 Variable rates (2.01% to 2.16% at 1/1/05) due 2015-2017 89,800 89,800 Non-collateralized:
Variable rates (2.0 1% to 2.16% at 1/1105) due 2021-2031 445,940 445,940 Total other long-tenn debt 560,140 560,140 Capitalized lease obligations 52 1,497 Unamortized debt premium (discount), net (4,930)
(8,470)
Total long-tenn debt (annual interest requirement -- $169.0 million) 4,080,262 3,903,167 Less amount due within one year 225,005 526,019 Long-term debt excluding amount due within one year
$3,855,257
$3,377,148 46.8%
44.7%
26
STATEMENTS OF CAPITALIZATION (continued)
At December 31, 2004 and 2003 Alabama Power Company 2004 Annual Report 2004 2003 2004 2003 (in thousands)
(percent oftotal)
Long-term Dcbt Payable to Affiliated Trusts:
4.75% through 2007 due 2042*
103,093 5.5% through 2009 due 2042*
206,186 Total long-term debt payable to affiliated trusts (annual interest requirement -- $16.2 million) 309,279 3.8 0.0 Mandatorily Redeemable Preferred Securities:
$1,000 liquidation value due 2042--
4.75% through 2007*
100,000 5.50% through 2009*
200,000 Total mandatorily redeemable preferred securities 300,000 0.0 4.0 Cumulative Preferred Stock:
$100 par or stated value -- 4.20% to 4.92%
47,611 47,512
$25 par or stated value -- 5.20% to 5.83%
294,105 200,000
$100,000 stated value -- 4.95%
123,331 125,000 Total cumulative preferred stock (annual dividend requirement -- $24.3 million) 465,047 372,512 5.6 4.9 Common Stockholder's Equity:
Common stock, par value $40 per share -
330,000 290,000 Authorized - 15,000,000 shares Outstanding - 8,250,000 shares in 2004 and 7,250,000 shares in 2003 Paid-in capital 1,955,183 1,927,069 Retained earnings 1,341,049 1,291,558 Accumulated other comprehensive income (loss)
(16,028)
(7,967)
Total common stockholder's equity 3,610,204 3,500,660 43.8 46.4 Total Capitalization
$8,239,787 S7,550,320 100.0%
100.0%
- The fixed rates thereafter are determined through remarketings for specific periods of varying length or at floating rates determined by reference to 3-month LIBOR plus 2.91% and 3.10%, respectively.
The accompanying notes are an integral part of these financial statements.
27
STATEMENTS OF COMMON STOCKHOLDER'S EQUITY For the Years Ended December 31, 2004, 2003, and 2002 Alabama Power Company 2004 Annual Report Other Common Paid-In Retained Comprehensive Stock Capital Earnings Income (loss)
Total (in thousands)
BalanceatDecember31,2001
$240,000
$1,850,775
$1,220,102 S
$3,310,877 Net income after dividends on preferred stock 461,355 461,355 Capital contributions from parent company 49,788 49,788 Other comprehensive income (loss)
(13,417)
(13,417)
Cash dividends on common stock (431,000)
(431,000)
Other 137 137 Balance at December 31, 2002 240,000 1,900,563 1,250,594 (13,417) 3,377,740 Net income after dividends on preferred stock 472,810 472,810 Issuance of common stock 50,000 50,000 Capital contributions from parent company 26,506 26,506 Other comprehensive income (loss) 5,450 5,450 Cash dividends on common stock (430,200)
(430,200)
Other (1,646)
(1,646)
Balance at December 31, 2003 290,000 1,927,069 1,291,558 (7,967) 3,500,660 Net income after dividends on preferred stock 481,171 481,171 Issuance of common stock 40,000 40,000 Capital contributions from parent company 28,213 28,213 Other comprehensive income (loss)
(8,061)
(8,061)
Cash dividends on common stock (437,300)
(437,300)
Other (99) 5,620 5,521 Balance at December 31, 2004
$330,000 S1,955,183 S1,341,049
$(16,028)
$3,610,204 The accompanying notes are an integral part of these financial statements.
STATEMENTS OF COMPREHENSIVE INCOME For the Years Ended December 31, 2004, 2003, and 2002 Alabama Power Company 2004 Annual Report 2004 2003 2002 (in thousands)
Net income after dividends on preferred stock S481,171
$472,810
$461,355 Other comprehensive income (loss):
Change in additional minimum pension liability, net of tax of
$(2,482), $(2,301) and $(2,536), respectively (4,083)
(3,785)
(4,172)
Change in fair value of marketable securities, net of tax of $252 414 Changes in fair value of qualifying hedges, net of tax of
$(4,807), $1,330 and $(6,430), respectively (7,906) 2,188 (10,576)
Less: Reclassification adjustment for amounts included in net income, net of tax of $2,136, $4,285 and $810, respectively 3,514 7,047 1,331 Total other comprehensive income (loss)
(8,061) 5,450 (13,417)
Comprehensive Income S473,110 S478,260
$447,938 The accompanying notes are an integral part of these financial statements.
28
NOTES TO FINANCIAL STATEMENTS Alabama Power Company 2004 Annual Report
- 1.
SUMMARY
OF SIGNIFICANT ACCOUNTING POLICIES General Alabama Power Company (the Company) is a wholly owned subsidiary of Southern Company, which is the parent company of five retail operating companies, Southern Power Company (Southern Power), Southern Company Services (SCS), Southern Communications Services (SouthemLINC Wireless), Southern Company Gas (Southern Company GAS), Southern Company Holdings (Southern Holdings), Southern Nuclear Operating Company (Southern Nuclear), Southern Telecom, and other direct and indirect subsidiaries. The retail operating companies -- the Company, Georgia Power Company, Gulf Power Company, Mississippi Power Company, and Savannah Electric and Power Company -- provide electric service in four Southeastern states. The Company operates as a vertically integrated utility providing electricity to retail customers within its traditional service area located within the State of Alabama and to wholesale customers in the Southeast.
Southern Power constructs, owns, and manages Southern Company's competitive generation assets and sells electricity at market-based rates in the wholesale market.
Contracts among the retail operating companies and Southern Power -- related to jointly-owned generating facilities, interconnecting transmission lines, or the exchange of electric power -- are regulated by the Federal Energy Regulatory Commission (FERC) and/or the Securities and Exchange Commission (SEC). SCS -- the system service company - provides, at cost, specialized services to Southern Company and its subsidiary companies. SouthernLINC Wireless provides digital wireless communications services to the retail operating companies and also markets these services to the public within the Southeast. Southern Telecom provides fiber cable services within the Southeast. Southern Company GAS is a competitive retail natural gas marketer serving customers in Georgia. Southern Holdings is an intermediate holding subsidiary for Southern Company's investments in synthetic fuels and leveraged leases and various other energy-related businesses. Southern Nuclear operates and provides services to Southern Company's nuclear power plants, including the Company's Plant Farley.
The equity method is used for subsidiaries in which the Company has significant influence but does not control and for variable interest entities where the Company is not the primary beneficiary. Certain prior years' data presented in the financial statements have been reclassified to conform with current year presentation.
Southern Company is registered as a holding company under the Public Utility Holding Company Act of 1935, as amended (PUHCA). Both Southern Company and its subsidiaries are subject to the regulatory provisions of the PUHCA. In addition, the Company is subject to regulation by the FERC and the Alabama Public Service Commission (Alabama PSC). The Company follows accounting principles generally accepted in the United States and complies with the accounting policies and practices prescribed by its regulatory commissions. The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires the use of estimates, and the actual results may differ from those estimates.
Affiliate Transactions The Company has an agreement with SCS under which the following services are rendered to the Company at direct or allocated cost: general and design engineering, purchasing, accounting and statistical analysis, finance and treasury, tax, information resources, marketing, auditing, insurance and pension administration, human resources, systems and procedures, and other services with respect to business and operations and power pool transactions.
Costs for these services amounted to $224 million, $217 million, and $218 million during 2004, 2003, and 2002, respectively. Cost allocation methodologies used by SCS are approved by the SEC and management believes they are reasonable.
The Company has an agreement with Southern Nuclear under which Southern Nuclear operates the Company's Plant Farley and provides the following nuclear-related services at cost: general executive and advisory services, general operations, management and technical services, administrative services including procurement, accounting, statistical analysis, employee relations, and other services with respect to business and operations. Costs for these services amounted to $169 million, $153 million, and $154 million during 2004, 2003, and 2002, respectively.
The Company jointly owns Plant Greene County with Mississippi Power. The Company has an agreement with Mississippi Power under which the Company operates Plant Greene County, and Mississippi Power reimburses the Company for its proportionate share of expenses which were $7.2 million in 2004, $6.6 million in 2003, and $6.4 million in 2002. See Note 4 for additional information.
29
__-U NOTES (continued)
Alabama Power Company 2004 Annual Report Southern Company holds a 30 percent ownership interest in Alabama Fuel Products, LLC (AFP), which produces synthetic fuel. The Company has an agreement with an indirect subsidiary of Southern Company that provides services for AFP. Under this agreement, the Company provides certain accounting functions, including processing and paying fuel transportation invoices, and the Company is reimbursed for its expenses. Amounts billed under this agreement totaled approximately S28.7 million,
$27.5 million, and S34.5 million in 2004, 2003 and 2002, respectively. In addition, the Company purchases synthetic fuel from AFP for use at several of the Company's plants. Fuel purchases for 2004, 2003, and 2002 totaled S236.9 million, $209.2 million, and $211.0 million, respectively.
In June 2003, the Company entered into an agreement with Southern Power under which the Company operates and maintains Plant Harris at cost. In 2004 and 2003, the Company billed Southern Power $1.8 million and SO.8 million, respectively, for operation and maintenance.
Under a power purchase agreement (PPA) with Southern Power, the Company's purchased power costs from Plant Harris in 2004 and 2003 totaled $59.0 million and $41.7 million, respectively. The Company also provides the fuel, at cost, associated with the PPA and the fuel cost recognized by the Company in 2004 was $65.7 million and
$33.9 million in 2003. Additionally, the Company recorded $8.3 million of prepaid capacity expenses included in Other Deferred Charges and Other Assets on the balance sheets at December 31, 2004 and 2003. See Note 3 under "Retail Rate Adjustment Procedures" and Note 7 under "Purchased Power Commitments" for additional information.
The Company has an agreement with SouthernLINC Wireless to provide digital wireless communications services to the Company. Costs for these services amounted to $5.3 million, $4.9 million, and $4.4 million during 2004, 2003, and 2002, respectively.
Also, see Note 4 for information regarding the Company's ownership in and PPA with Southern Electric Generating Company (SEGCO) and Note 5 for information on certain deferred tax liabilities due to affiliates.
The retail operating companies, including the Company, Southern Power, and Southern Company GAS jointly enter into various types of wholesale energy, natural gas, and certain other contracts, either directly or through SCS as agent. Each participating company may be jointly and severally liable for the obligations incurred under these agreements.
Fuel Costs Fuel costs are expensed as the fuel is used. Fuel expense includes the cost of purchased emission allowances as they are used. Fuel expense also includes the amortization of the cost of nuclear fuel and a charge, based on nuclear generation, for the permanent disposal of spent nuclear fuel. Total charges for nuclear fuel included in fuel expense amounted to $61 million in 2004, $64 million in 2003, and $63 million in 2002. The Company has a contract with the U.S. Department of Energy (DOE) that provides for the permanent disposal of spent nuclear fuel.
The DOE failed to begin disposing of spent nuclear fuel in 1998 as required by the contract, and the Company is pursuing legal remedies against the government for breach of contract. Sufficient pool storage capacity for spent fuel is available at Plant Farley to maintain full-core discharge capability until the refueling outage scheduled in 2006 for Plant Farley Unit I and the refueling outage scheduled in 2008 for Plant Farley Unit 2. Construction of an on-site dry spent fuel storage facility at Plant Farley is in progress and scheduled for operation in 2005. The onsite storage facility is expected to provide adequate spent fuel storage through 2015 for both units and can be expanded to provide storage through 2025. See Note 7 under "Construction Program" for additional information.
Also, the Energy Policy Act of 1992 established a Uranium Enrichment Decontamination and Decommissioning Fund, which is funded in part by a special assessment on utilities with nuclear plants. This assessment is being paid over a 15-year period, which began in 1993. This fund will be used by the DOE for the decontamination and decommissioning of its nuclear fuel enrichment facilities. The law provides that utilities will recover these payments in the same manner as any other fuel expense. The Company estimates its remaining liability at December 31, 2004 under this law to be approximately $9 million.
Regulatory Assets and Liabilities The Company is subject to the provisions of Financial Accounting Standards Board (FASB) Statement No. 71, Accounting for the Effects of Certain Types of Regulation. Regulatory assets represent probable future revenues associated with certain costs that are expected to be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are 30
NOTES (continued)
Alabanm rower Company 2004 Annual Report expected to be credited to customers through the ratemaking process.
Regulatory assets and (liabilities) reflected in the balance sheets at December 31 relate to:
2004 2003 Note (in millions)
Deferred income tax charges S 317 $ 321 (a)
Loss on reacquired debt 109 111 (b)
DOE assessments 9
13 (c)
Vacation pay 36 36 (d)
Rate CNP under recovery 18 17 (e)
Natural disaster reserve 38 (13)
(e)
Fuel-hedging assets 6
(f)
Other assets 14 (1)
(e)
Asset retirement obligations (159) (127)
(a)
Other cost of removal obligations (597) (573)
(a)
Deferred income tax credits (148) (162)
(a)
Deferred purchased power (19)
(15)
(e)
Other liabilities (2)
(5)
(e)
Mine reclamation & remediation (25)
(33)
(e)
Fuel-hedging liabilities (10)
(6)
(f Total
$(413)$(437)
Note: The recovery and amortization periods for these regulatory assets and (liabilities) are as follows:
(a)
Asset retirement and removal liabilities are recorded, deferred income tax assets are recovered, and deferred tax liabilities are amortized over the related property lives, which may range up to 50 years. Asset retirement and removal liabilities will be settled and trued up following completion of the related activities.
(b)
Recovered over the remaining life of the original issue which may range up to 50 years.
(c)
Assessments for the decontamination and decommissioning of the DOE nuclear fuel enrichment facilities are recorded annually from 1993 through 2008.
(d)
Recorded as earned by employees and recovered as paid, generally within one year.
(e)
Recorded and recovered or amortized as approved by the Alabama PSC.
(D)
Fuel-hedging assets and liabilities are recorded over the life of the underlying hedged purchase contracts, which generally do not exceed two years. Upon final settlement, actual costs incurred are recovered through the fuel cost recovery clauses.
In the event that a portion of the Company's operations is no longer subject to the provisions of FASB Statement No. 71, the Company would be required to write off related regulatory assets and liabilities that are not specifically recoverable through regulated rates. In addition, the Company would be required to determine if any impairment to other assets exists, including plant, and write down the assets, if impaired, to their fair values. All regulatory assets and liabilities are currently reflected in rates.
Revenues Energy and other revenues are recognized as services are provided. Capacity revenues are generally recognized on a levelized basis over the appropriate contract periods.
Unbilled revenues are accrued at the end of each fiscal period. Electric rates for the Company include provisions to adjust billings for fluctuations in fuel costs, fuel hedging, the energy component of purchased power costs, and certain other costs. Revenues are adjusted for differences between the actual recoverable costs and amounts billed in current regulated rates.
The Company has a diversified base of customers. No single customer or industry comprises 10 percent or more of revenues. For all periods presented, uncollectible accounts averaged less than I percent of revenues.
Income Taxes The Company uses the liability method of accounting for deferred income taxes and provides deferred income taxes for all significant income tax temporary differences.
Investment tax credits utilized are deferred and amortized to income over the average life of the related property.
Depreciation and Amortization Depreciation of the original cost of depreciable utility plant in service is provided primarily by using composite straight-line rates, which approximated 3.0 percent in 2004, 3.1 percent in 2003, and 3.2 percent in 2002. When property subject to depreciation is retired or otherwise disposed of in the normal course of business, its original cost -- together with the cost of removal, less salvage -- is charged to accumulated depreciation. Minor items of property included in the original cost of the plant are retired when the related property unit is retired.
Asset Retirement Obligations and Other Costs of Removal Effective January 1, 2003, the Company adopted FASB Statement No. 143, Accounting for Asset Retirement Obligations. Statement No. 143 establishes new accounting and reporting standards for legal obligations associated with the ultimate costs of retiring long-lived assets. The present value of the ultimate costs of an asset's future retirement is recorded in the period in which the liability is incurred. The costs are capitalized as part of the related long-lived asset and depreciated over the asset's useful life. Although Statement No. 143 does not permit the continued accrual of future 31
-U.
NOTES (continued)
Alabama Po*cr Company 2004 Annual Report retirement costs for long-lived assets that the Company does not have a legal obligation to retire, the Company has received accounting guidance from the Alabama PSC allowing such treatment. Accordingly, the accumulated removal costs for other obligations previously accrued will continue to be reflected on the balance sheets as a regulatory liability. Therefore, the Company had no cumulative effect to net income resulting from the adoption of Statement No. 143.
The liability recognized to retire long-lived assets primarily relates to the Company's nuclear facility, Plant Farley. The fair value of assets legally restricted for settling retirement obligations related to nuclear facilities as of December 31, 2004 was $446 million.
In addition, the Company has retirement obligations related to various landfill sites and underground storage tanks. The Company has also identified retirement obligations related to certain transmission and distribution facilities, co-generation facilities, certain wireless communication towers, and certain structures authorized by the United States Army Corps of Engineers. However, liabilities for the removal of these transmission and distribution assets have not been recorded because no reasonable estimate can be made regarding the timing of the obligations. The Company will continue to recognize in the statements of income allowed removal costs in accordance with its regulatory treatment. Any difference between costs recognized under Statement No. 143 and those reflected in rates are recognized as either a regulatory asset or liability, as ordered by the Alabama PSC, and are reflected in the balance sheets. See "Nuclear Decommissioning" herein for further information on amounts included in rates.
Details of the asset retirement obligations included in the balance sheets are as follows:
Nuclear Decommissioning The Nuclear Regulatory Commission (NRC) requires licensees of commercial nuclear power reactors to establish a plan for providing reasonable assurance of funds for future decommissioning. The Company has established external trust funds to comply with the NRC's regulations. The funds set aside for decommissioning are managed and invested in accordance with applicable requirements of various regulatory bodies, including the NRC, the FERC, and the Alabama PSC, as well as the Internal Revenue Service (IRS). Funds are invested in a tax efficient manner in a diversified mix of equity and fixed income securities. Equity securities typically range from 50 to 75 percent of the funds and fixed income securities from 25 to 50 percent. Amounts previously recorded in internal reserves are being transferred into the external trust funds over periods approved by the Alabama PSC. The NRC's minimum external funding requirements are based on a generic estimate of the cost to decommission only the radioactive portions of a nuclear unit based on the size and type of reactor. The Company has filed plans with the NRC to ensure that -- over time --
the deposits and earnings of the external trust funds will provide the minimum funding amounts prescribed by the NRC.
Site study cost is the estimate to decommission the facility as of the site study year. The estimated costs of decommissioning, based on the most current study as of December 31, 2004, for Plant Farley were as follows:
Decommissioning periods:
Beginning year Completion year 2017 2046 (in millions)
Site study costs:
Radiated structures
$892 Non-radiated structures 63 Total
$955 Balance beginning of year Liabilities incurred Liabilities settled Accretion Cash flow revisions Balance end of year 2004 2003 (in millions)
$359 301 25 23 35
$384
$359 The decommissioning cost estimates are based on prompt dismantlement and removal of the plant from service. The actual decommissioning costs may vary from the above estimates because of changes in the assumed date of decommissioning, changes in NRC requirements, or changes in the assumptions used in making these estimates.
32
NOTES (continued)
Alabama Power Company 2004 Annual Report Annual provisions for nuclear decommissioning are based on an annuity method as approved by the Alabama PSC. The amount expensed in 2004 and fund balances were as follows:
(in millions)
Amount expensed in 2004 S 18 Accumulated provisions:
External trust funds, at fair value
$446 Internal reserves 29 Total
$475 All of the Company's decommissioning costs for ratemaking are based on the site study. The Company expects the Alabama PSC to periodically review and adjust, if necessary, the amounts paid into the reserve and deposited into external trusts. Significant assumptions used to determine these costs for ratemaking were an inflation rate of 4.5 percent and a trust earnings rate of 7.0 percent.
The Company filed an application with the NRC in September 2003 to extend the operating license for Plant Farley for an additional 20 years. The NRC is expected to rule on the application by July 2005. If the NRC approves the extension, the annual provision for nuclear decommissioning could decrease, subject to Alabama PSC approval.
Allowance for Funds Used During Construction (AFUDC)
In accordance with regulatory treatment, the Company records AFUDC. AFUDC represents the estimated debt and equity costs of capital funds that are necessary to finance the construction of new regulated facilities. While cash is not realized currently from such allowance, it increases the revenue requirement over the service life of the plant through a higher rate base and higher depreciation expense. All current construction costs are included in retail rates. The composite rate used to determine the amount of AFUDC was 8.6 percent in 2004, 9.0 percent in 2003, and 8.2 percent in 2002. AFUDC, net of income tax, as a percent of net income after dividends on preferred stock was 4.2 percent in 2004, 3.5 percent in 2003, and 3.3 percent in 2002.
Property, Plant, and Equipment Property, plant, and equipment is stated at original cost less regulatory disallowances and impairments. Original cost includes: materials; labor; minor items of property; appropriate administrative and general costs; payroll-related costs such as taxes, pensions, and other benefits; and the interest capitalized and/or cost of funds used during construction.
The cost of replacements of property -- exclusive of minor items of property -- is capitalized. The cost of maintenance, repairs and replacement of minor items of property is charged to maintenance expense as incurred or performed with the exception of nuclear refueling costs, which are recorded in accordance with specific Alabama PSC orders. The Company accrues estimated refueling costs in advance of the unit's next refueling outage. The refueling cycle is 18 months for each unit. During 2004, the Company accrued $22.6 million to the nuclear refueling outage reserve and at December 31, 2004 the reserve balance was a regulatory asset of S0.6 million.
Impairment of Long-Lived Assets and Intangibles The Company evaluates long-lived assets for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. The determination of whether an impairment has occurred is based on either a specific regulatory disallowance or an estimate of undiscounted future cash flows attributable to the assets, as compared with the carrying value of the assets. If an impairment has occurred, the amount of the impairment recognized is determined by either the amount of the regulatory disallowance or by estimating the fair value of the assets and recording a provision for loss if the carrying value is greater than the fair value. For assets identified as held for sale, the carrying value is compared to the estimated fair value less the cost to sell in order to determine if an impairment provision is required. Until the assets are disposed of, their estimated fair value is re-evaluated when circumstances or events change.
Cash and Cash Equivalents For purposes of the financial statements, temporary cash investments are considered cash equivalents. Temporary cash investments are securities with original maturities of 90 days or less.
33
NOTES (continued)
Alabama Power Company 2004 Annual Report Materials andl Supplies Generally, materials and supplies include the average cost of transmission, distribution, and generating plant materials. Materials are charged to inventory when purchased and then expensed or capitalized to plant, as appropriate, when installed.
Natural Disaster Reserve The pro forma impact of fair-value accounting for options granted on earnings is as follows:
Net Income As Pro Reported Forma (in thousands)
$481,171
$478,317 472,810 469,599 461,355 457,928 2004 2003 2002 In accordance with an Alabama PSC order, the Company has established a natural disaster reserve to cover the cost of uninsured damages from major storms to transmission and distribution lines and to generation facilities and other property. The Company is allowed to accrue $250 thousand per month until the maximum accumulated provision of $32 million is attained. Higher accruals to restore the reserve to its authorized level are allowed whenever the balance in the reserve declines below S22.4 million. During 2004, the Company accrued S9.9 million, including an additional amount of $6.9 million, to the reserve and at December 31, 2004, the reserve balance was a regulatory asset of $37.7 million. See Note 3 under "Natural Disaster Cost Recovery" for further information.
Environmental Cost Recovery The Company must comply with environmental laws and regulations that cover the handling and disposal of waste and releases of hazardous substances. Under these various laws and regulations, the Company may also incur substantial costs to clean up properties. The Company has received authority from the Alabama PSC to recover approved environmental compliance costs through specific retail rate clauses. Within limits approved by the Alabama PSC, these rates are adjusted annually. See Note 3 under "Retail Regulatory Matters" for additional information.
Stock Options Southern Company provides non-qualified stock options to a large segment of the Company's employees ranging from line management to executives. The Company accounts for its stock-based compensation plans in accordance with Accounting Principles Board Opinion No. 25.
Accordingly, no compensation expense has been recognized because the exercise price of all options granted equaled the fair-market value of Southern Company's common stock on the date of grant. When options are exercised, the Company receives a capital contribution from Southern Company equivalent to the related income tax benefit.
The estimated fair values of stock options granted in 2004, 2003, and 2002 were derived using the Black-Scholes stock option pricing model. The following table shows the assumptions and the weighted average fair values of stock options:
2004 2003 2002 Interest rate 3.1%
2.7%
2.8%
Average expected life of stock options (in years) 5.0 4.3 4.3 Expected volatility of common stock 19.6%
23.6%
26.3%
Expected annual dividends on common stock S1.40
$1.37
$1.34 Weighted average fair value of stock options granted S3.29
$3.59
$3.37 Financial Instruments The Company uses derivative financial instruments to limit exposure to fluctuations in interest rates, the prices of certain fuel purchases, and electricity purchases and sales.
All derivative financial instruments are recognized as either assets or liabilities and are measured at fair value.
Substantially all of the Company's bulk energy purchases and sales contracts that meet the definition of a derivative are exempt from fair value accounting requirements and are accounted for under the accrual method. Other derivative contracts qualify as cash flow hedges of anticipated transactions. This results in the deferral of related gains and losses in other comprehensive income or regulatory assets or liabilities as appropriate until the hedged transactions occur. Any ineffectiveness is recognized currently in net income. Other derivative contracts are marked to market through current period income and are recorded on a net basis in the statements of income.
The Company is exposed to losses related to financial instruments in the event of counterparties' nonperformance. The Company has established controls to determine and monitor the creditworthiness of counterparties in order to mitigate the Company's exposure to counterparty credit risk.
34
NOTES (continued)
Alabama Power Company 2004 Annual Report The Company's other financial instruments for which the carrying amount did not equal fair value at December 31 were as follows:
Carrying Fair Amount Value (in millions)
Long-term debt:
At December 31, 2004 At December 31, 2003 Preferred Securities:
At December 31,2004 At December 31, 2003
$4,389 54,454 3,903 3,958
- 2. RETIREMENT BENEFITS The Company has a defined benefit, trusteed, pension plan covering substantially all employees. The plan is funded in accordance with Employee Retirement Income Security Act of 1974, as amended (ERISA), requirements. No contributions to the plan are expected for the year ending December 31, 2005. The Company also provides certain non-qualified benefit plans for a selected group of management and highly-compensated employees.
Benefits under these non-qualified plans are funded on a cash basis. In addition, the Company provides certain medical care and life insurance benefits for retired employees. The Company funds trusts to the extent required by the Alabama PSC. For the year ended December 31, 2005, postretirement trust contributions are expected to total approximately $25.3 million.
The measurement date for plan assets and obligations is September 30 for each year.
Pension Plans 300 305 The fair values were based on either closing market price or closing price of comparable instruments. See "Variable Interest Entities" herein and Note 6 under "Mandatorily Redeemable Preferred Securities/Long-Term Debt Payable to Affiliate Trusts" for further information regarding the accounting treatment of the preferred securities, which underlie the Company's long-term debt payable to affiliated trusts.
Comprehensive Income The objective of comprehensive income is to report a measure of all changes in common stock equity of an enterprise that result from transactions and other economic events of the period other than transactions with owners.
Comprehensive income consists of net income, changes in the fair value of qualifying cash flow hedges and marketable securities, and changes in additional minimum pension liability, less income taxes and reclassifications for amounts included in net income.
Variable Interest Entities On March 31, 2004, the Company prospectively adopted FASB Interpretation No. 46R, "Consolidation of Variable Interest Entities," which requires the primary beneficiary of a variable interest entity to consolidate the related assets and liabilities. The adoption of Interpretation No.
46R had no impact on the net income of the Company.
However, as a result of the adoption, the Company deconsolidated certain wholly-owned trusts established to issue preferred securities since the Company is not the primary beneficiary of the trusts. Therefore, the investments in these trusts are reflected as Other Investments, and the related loans from the trusts are reflected as Long-term Debt Payable to Affiliated Trusts on the balance sheets. This treatment resulted in a $9 million increase in both total assets and total liabilities as of March 31,2004.
The accumulated benefit obligation for the pension plans was $1.21 billion in 2004 and $1.10 billion in 2003.
Changes during the year in the projected benefit obligations, accumulated benefit obligations, and fair value of plan assets were as follows:
Projected Benefit Obligations 2004 2003 (in millions)
Balance at beginning of year S1,200
$1,088 Service cost 30 27 Interest cost 71 68 Benefits paid (64)
(61)
Plan amendments 1
3 Actuarial (gain) loss 87 75 Balance at end of year
$1,325
$1,200 Plan Assets 2004 2003 (in millions)
Balance at beginning of year
$1,583
$1,419 Actual return on plan assets 157 226 Benefits paid' (64)
(62)
Balance at end of year
$1,676
$1,583 Pension plan assets are managed and invested in accordance with all applicable requirements, including ERISA and the Internal Revenue Code of 1986, as amended (Internal Revenue Code). Southern Company's investment policy covers a diversified mix of assets, including equity and fixed income securities, real estate, 35
.11 NOTES (continued)
Alabama Powvcr Company 2004 Annual Report and private equity, as described in the table below.
Derivative instruments are used primarily as hedging tools but may also be used to gain efficient exposure to the various asset classes. Southern Company primarily minimizes the risk of large losses through diversification but also monitors and manages other aspects of risk.
Plan Assets Target 2004 2003 Domestic equity 37%
36%
37%
International equity 20 20 20 Fixed income 26 26 24 Real estate 10 10 II Private equity 7
8 8
Total 100%
100%
100%
The reconciliations of the funded status with the accrued pension costs recognized in the balance sheets were as follows:
2004 2003 (in millions)
Funded status S351
$383 Unrecognized transition amount (5)
Unrecognized prior service cost 80 87 Unrecognized net (gain) loss 27 (37)
Prepaid pension asset, net S458
$428 The prepaid pension asset, net is reflected in the balance sheets in the following line items:
2004 2003 (in millions)
Prepaid pension asset
$489
$446 Employee benefit obligations (60)
(39)
Intangible asset 10 8
Accumulated other comprehensive income 19 13 Prepaid pension asset, net
$458
$428 Components of the pension plans' net periodic cost wvere as follows:
2004 2003 2002 (in millions)
Service cost
$ 30 S 27 S 26 Interest cost 71 68 74 Expected return on plan assets (138)
(138)
(138)
Recognized net gain (3)
(12)
(20)
Net amortization 4
3 2
Net pension cost (income)
$ (36) $ (52) S (56) plans. At December 31, 2004, estimated benefit payments were as follows:
2005 2006 2007 2008 2009 2010 to 2014 Benefit Payments (in millions)
$ 63.9 64.3 65.3 66.9 69.4 S412.6 Postretirement Benefits Changes during the year in the accumulated benefit obligations and in the fair value of plan assets wvere as follows:
Accumulated Benefit Obligations 2004 2003 (in millions)
Balance at beginning of year
$441
$405 Service cost 7
6 Interest cost 24 26 Benefits paid (18)
(20)
Actuarial (gain) loss 11 24 Balance at end of year S465
$441 Plan Assets 2004 2003 (in millions)
Balance at beginning of year S186
$158 Actual return on plan assets 24 25 Employer contributions 20 23 Benefits paid (18)
(20)
Balance at end of year S212
$186 Postretirement benefits plan assets are managed and invested in accordance with all applicable requirements, including ERISA and the Internal Revenue Code. The Company's investment policy covers a diversified mix of assets, including equity and fixed income securities, real estate, and private equity, as described in the table below.
Derivative instruments are used primarily as hedging tools but may also be used to gain efficient exposure to the various asset classes. The Company primarily minimizes the risk of large losses through diversification but also monitors and manages other aspects of risk.
Future benefit payments reflect expected future service and are estimated based on assumptions used to measure the projected benefit obligations for the pension 36
NOTES (continued)
Alabama Power Company 2004 Annual Report Plan Assets Target 2004 2003 Domestic equity 46%
46%
50%
International equity 13 13 14 Fixed income 34 33 28 Real estate 4
5 5
Private equity 3
3 3
Total 100%
100%
100%
The accrued postretirement costs recognized in the balance sheets were as followvs:
Future benefit payments, including prescription drug benefits, reflect expected future service and are estimated based on assumptions used to measure the accumulated benefit obligation for the postretirement plans. Estimated benefit payments are reduced by drug subsidy receipts expected as a result of the Medicare Act as follows:
Benefit Subsidy Payments Receipts Total (in millions) 2005
$ 20.7 S 20.7 2006 22.0 (2.9) 19.1 2007 23.3 (3.1) 20.2 2008 25.2 (3.4) 21.8 2009 27.8 (3.8) 24.0 2010 to 2014
$173.2
$(24.3)
$148.9 Funded status Unrecognized transition obligation Unrecognized prior service cost Unrecognized net loss (gain)
Fourth quarter contributions Accrued liability recognized in the balance sheets 2004 2003 (in millions)
S(253)
$(255) 33 37 68 73 87 82 9
6 S (56)
$ (57)
Components of the postretirement plans' net periodic cost were as follows:
2004 2003 2002 (in millions)
Service cost S 7
$ 6
$ 5 Interest cost 24 25 25 Expected return on plan assets (18)
(17)
(16)
Net amortization 9
9 9
Net postretirement cost
$ 22
$ 23
$ 23 In the third quarter 2004, the Company prospectively adopted FASB Staff Position (FSP) 106-2, Accounting and Disclosure Requirements related to the Medicare Prescription Drug, Improvement, and Modernization Act of 2003 (the Medicare Act). The Medicare Act provides a 28 percent prescription drug subsidy for Medicare eligible retirees. FSP 106-2 requires recognition of the impacts of the Medicare Act in the accumulated postretirement benefit obligation (APBO) and future cost of service for postretirement medical plans. The effect of the subsidy reduced the Company's expenses for the six months ended December 31, 2004 by approximately $3.2 million and is expected to have a similar impact on future expenses.
The subsidy's impact on the postretirement medical plan APBO was a reduction of approximately $59.8 million. However, the ultimate impact on future periods is subject to federal regulations governing the subsidy created in the Medicare Act which are being finalized.
The weighted average rates assumed in the actuarial calculations used to determine both the benefit obligations and the net periodic costs for the pension and postretirement benefit plans were as follows:
2004 2003 2002 Discount 5.75% 6.00% 6.50%
Annual salary increase 3.50 3.75 4.00 Long-term return on plan assets 8.50 8.50 8.50 The Company determined the long-term rate of return based on historical asset class returns and current market conditions, taking into account the diversification benefits of investing in multiple asset classes.
An additional assumption used in measuring the accumulated postretirement benefit obligations was a weighted average medical care cost trend rate of 11 percent for 2004, decreasing gradually to 5 percent through the year 2012, and remaining at that level thereafter. An annual increase or decrease in the assumed medical care cost trend rate of I percent would affect the accumulated benefit obligation and the service and interest cost components at December 31, 2004 as follows:
I Percent I Percent Increase Decrease (in millions)
Benefit obligation
$41 S32 Service and interest costs 2
2 Employee Savings Plan The Company also sponsors a 40 1(k) defined contribution plan covering substantially all employees. The Company provides a 75 percent matching contribution up to 6 37
__ _ _ _ _ _ _ _ _ _ _ iI NOTES (continued)
Alabama Power Company 2004 Annual Report percent of an employee's base salary. Total matching contributions made to the plan for 2004, 2003, and 2002 were $13 million, S12 million, and $12 million, respectively.
- 3. CONTINGENCIES AND REGULATORY MATTERS General Litigation Matters The Company is subject to certain claims and legal actions arising in the ordinary course of business. In addition, the Company's business activities are subject to extensive governmental regulation related to public health and the environment. Litigation over environmental issues and claims of various types, including property damage, personal injury, and citizen enforcement of environmental requirements, has increased generally throughout the United States. In particular, personal injury claims for damages caused by alleged exposure to hazardous materials have become more frequent. The ultimate outcome of such litigation against the Company cannot be predicted at this time; however, management does not anticipate that the liabilities, if any, arising from such current proceedings would have a material adverse effect on the Company's financial statements.
Environmental Matters New Source Review Actions In November 1999, the Environmental Protection Agency (EPA) brought a civil action in the U.S. District Court for the Northern District of Georgia against the Company.
The complaint alleged violations of the New Source Review (NSR) provisions of the Clean Air Act and related state laws with respect to coal-fired generating facilities at the Company's Plants Miller, Barry, and Gorgas. The EPA concurrently issued to the Company a notice of violation relating to these specific facilities, as well as Plants Greene County and Gaston. In early 2000, the EPA filed a motion to amend its complaint to add the violations alleged in its notice of violation.
The U.S. District Court in Georgia subsequently granted the Company's motion to dismiss for lack of jurisdiction in Georgia. In March 2001, the court granted the EPA's motion to add Savannah Electric as a defendant. As directed by the court, the EPA refiled its amended complaint limiting claims to those brought against Georgia Power and Savannah Electric. In addition, the EPA refiled its claims against the Company in the U.S. District Court for the Northern District of Alabama. These civil complaints allege violations with respect to eight coal-fired generating facilities in Alabama and Georgia, and they request penalties and injunctive relief, including an order requiring the installation of the best available control technology at the affected units. The EPA has not refiled against Gulf Power or Mississippi Power.
The actions against the Company, Georgia Power, and Savannah Electric were effectively stayed in the spring of 2001 during the appeal of a similar NSR enforcement action against the Tennessee Valley Authority (TVA) before the U.S. Court of Appeals for the Eleventh Circuit. In June 2003, the Court of Appeals issued its ruling in the TVA case, dismissing the appeal for reasons unrelated to the issues in the cases pending against the Company, Georgia Power, and Savannah Electric. In May 2004, the U.S. Supreme Court denied the EPA's petition for review of the case.
In June 2004, the U.S. District Court for the Northern District of Alabama lifted the stay in the action against Alabama Power, placing the case back onto the Court's active docket. At this time, no party to the case against Georgia Power and Savannah Electric has sought to reopen that case, which remains administratively closed in the District Court for the Northern District of Georgia.
Since the inception of the NSR proceedings against the Company, Georgia Power, and Savannah Electric, the EPA has also been proceeding with similar NSR enforcement actions against other utilities, involving many of the same legal issues. In each case, the EPA alleged that the utilities failed to comply with the NSR permitting requirements when performing maintenance and construction activities at coal-burning plants, which activities the utilities considered to be routine or othervise not subject to NSR. District courts addressing these cases have, to date, issued opinions that reached conflicting conclusions.
The Company believes that it complied with applicable laws and the EPA regulations and interpretations in effect at the time the work in question took place. The Clean Air Act authorizes maximum civil penalties of $25,000 to $32,500 per day, per violation at each generating unit, depending on the date of the alleged violation. An adverse outcome in any one of these cases could require substantial capital expenditures that cannot be determined at this time and could possibly require payment of substantial penalties. This could affect future results of operations, cash flows, and possibly financial condition if such costs are not recovered through regulated rates.
38
NOTES (continued)
Alabama Power Company 2004 Annual Report In December 2002 and October 2003, the EPA issued final revisions to its NSR regulations under the Clean Air Act. The December 2002 revisions included changes to the regulatory exclusions and the methods of calculating emissions increases. The October 2003 regulations clarified the scope of the existing Routine Maintenance, Repair, and Replacement (RMRR) exclusion. A coalition of states and environmental organizations has filed*
petitions for review of these revisions with the U.S. Court of Appeals for the District of Columbia Circuit. The October 2003 RMRR rules have been stayed by the Court of Appeals pending its review of the rules. In any event, the final regulations must be adopted by the State of Alabama in order to apply to the Company's facilities.
The effect of these final regulations, related legal challenges, and potential state rulemakings cannot be determined at this time.
Generation Interconnection Agreements In July 2003, the FERC issued its final rule on the standardization of generation interconnection agreements and procedures (Order 2003). Order 2003 shifts much of the financial burden of new transmission investment from the generator to the transmission provider. The FERC has indicated that Order 2003, which was effective January 20, 2004, is to be applied prospectively to interconnection agreements. Subsidiaries of Tenaska, Inc., as counterparties to two previously executed interconnection agreements with the Company, have filed complaints at the FERC requesting that the FERC modify the agreements and that the Company refund a total of $ 11 million previously paid for interconnection facilities, with interest. The Company has also received similar requests from other entities totaling $2.5 million. The Company has opposed such relief, and the proceedings are still pending. The impact of Order 2003 and its subsequent rehearings on the Company and the final results of these matters cannot be determined at this time.
51arket-Based Rate Authority The Company has authorization from the FERC to sell power to nonaffiliates at market-based prices. Through SCS, as agent, the Company also has FERC authority to make short-term opportunity sales at market rates.
Specific FERC approval must be obtained with respect to a market-based contract with an affiliate. In November 2001, the FERC modified the test it uses to consider utilities' applications to charge market-based rates and adopted a new test called the Supply Margin Assessment (SMA). The FERC applied the SMA to several utilities, including Southern Company, the retail operating companies, and Southern Power, and found them and others to be "pivotal suppliers" in their retail service territories and ordered the implementation of several mitigation measures. Southern Company and others sought rehearing of the FERC order, and the FERC delayed the implementation of certain mitigation measures. In April 2004, the FERC issued an order that abandoned the SMA test and adopted a new interim analysis for measuring generation market power. This new interim approach requires utilities to submit a pivotal supplier screen and a wholesale market share screen. If the applicant does not pass both screens, there will be a rebuttable presumption regarding generation market power. The FERC's order also sets forth procedures for rebutting these presumptions and addresses mitigation measures for those entities that are found to have market power. In the absence of specific mitigation measures, the order includes several cost-based mitigation measures that would apply by default.
The FERC also initiated a new rulemaking proceeding that, among other things, will adopt a final methodology for assessing generation market power.
In July 2004, the FERC denied Southern Company's request for rehearing, along with a number of others, and reaffirmed the interim tests that it adopted in April. In August 2004, Southern Company submitted a filing to the FERC that included results showing that Southern Company passed the pivotal supplier screen for all markets and the wholesale market share screen for all markets except the Southern Company retail service territory. Southern Company also submitted other analyses to demonstrate that it lacks generation market power. On December 17, 2004, the FERC initiated a proceeding to assess Southern Company's generation dominance within its retail service territory. The ability to charge market-based rates in other markets is not at issue. As directed by this order, Southern Company submitted additional information on February 15, 2005 related to generation dominance in its retail service territory. Any new market based rate transactions in Southern Company's retail service territory entered into after February 27, 2005 will be subject to refund to the level of the default cost-based rates, pending the outcome of the proceeding. Southern Company, along with other utilities, has also filed an appeal of the FERC's April and July 2004 orders with the U.S. Court of Appeals for the District of Columbia Circuit. The FERC has asked the court to dismiss the appeal on the grounds that it is premature.
In the event that the FERC's default mitigation measures are ultimately applied, the Company may be required to charge cost-based rates for certain wholesale sales in Southern Company's retail service 39
NOTES (continued)
Alabama Poer Company 2004 Annual Report territory, which may be lower than negotiated market-based rates. The final outcome of this matter will depend on the form in which the final methodology for assessing generation market power and mitigation rules may be ultimately adopted and cannot be determined at this time.
Natural Disaster Cost Recovery In September 2004, Hurricane Ivan hit the Gulf Coast of Florida and Alabama and continued north through the Company's service territory causing substantial damage.
The related costs charged to the Company's natural disaster reserve were $57.8 million. During 2004, the Company accrued $9.9 million to the reserve and at December 31, 2004, the reserve balance was a regulatory asset of 537.7 million.
In February 2005, the Company requested and received Alabama PSC approval of an accounting order that allows the Company to immediately return certain regulatory liabilities to the retail customers. The order also allows the Company to simultaneously recover from customers an accrual of approximately $45 million to offset the costs of Hurricane Ivan and restore the natural disaster reserve. The combined effects of this order will have no impact on the Company's net income in 2005.
Retail Regulatory Matters The Alabama PSC has adopted a Rate Stabilization and Equalization plan (Rate RSE) that provides for periodic annual adjustments based upon the Company's earned return on end-of-period retail common equity. Such annual adjustments are limited to 3 percent. Rates remain unchanged when the return on common equity ranges between 13.0 percent and 14.5 percent. The Alabama PSC has also approved a rate mechanism that provides for adjustments to recognize the placing of new generating facilities in retail service and for the recovery of retail costs associated with certificated purchased power agreements (Rate CNP). Both increases and decreases have been placed into effect since the adoption of these rates.
In accordance with Rate RSE, a 2 percent increase in retail rates was effective in April 2002, amounting to an annual increase of $55 million. Also, to recover certificated purchased power costs under Rate CNP, an increase of 2.6 percent in retail rates, or S79 million annually, was effective July 2003. An additional increase of $25 million annually was effective July 2004 under Rate CNP for new certificated purchased power costs. In April 2005, an annual true-up adjustment to Rate CNP will decrease retail rates by approximately 0.5 percent, or S18.5 million annually.
In October 2004, the Alabama PSC approved a request by the Company to amend Rate CNP to also provide for the recovery of retail costs associated with environmental laws and regulations, effective in January 2005. In conjunction with the Alabama PSC's approval, the Company agreed to a moratorium until March 2007 on any retail rate increase under Rate RSE.
Any increase in March 2007 would be based upon the earned return on retail common equity at December 31, 2006 and would become effective with the April 2007 billing.
The Company's fuel costs are recovered under Rate ECR (Energy Cost Recovery), which provides for the addition of a fuel and energy cost factor to base rates.
In April 2005, this factor is scheduled to increase from its current level.
The ratemaking procedures will remain in effect until the Alabama PSC votes to modify or discontinue them.
- 4. JOINT OWNERSHIP AGREEMENTS The Company and Georgia Power own equally all of the outstanding capital stock of SEGCO, which owns electric generating units with a total rated capacity of 1,020 megawatts, as well as associated transmission facilities.
The capacity of these units is sold equally to the Company and Georgia Power under a contract which, in substance, requires payments sufficient to provide for the operating expenses, taxes, interest expense and a return on equity, whether or not SEGCO has any capacity and energy available. The term of the contract extends automatically for two-year periods, subject to either party's right to cancel upon two year's notice. The Company's share of purchased power totaled $86 million in 2004, $87 million in 2003, and $84 million in 2002 and is included in "Purchased power from affiliates" in the statements of income. The Company accounts for SEGCO using the equity method on the balance sheets.
In addition the Company has guaranteed unconditionally the obligation of SEGCO under an installment sale agreement for the purchase of certain pollution control facilities at SEGCO's generating units, pursuant to which $24.5 million principal amount of pollution control revenue bonds are outstanding. Also, the Company has guaranteed $50 million principal amount of unsecured senior notes issued by SEGCO for general corporate purposes. Georgia Power has agreed to reimburse 40
NOTES (continued)
Alabama Power Company 2004 Annual Report the Company for the pro rata portion of such obligations corresponding to its then proportionate ownership of stock of SEGCO if the Company is called upon to make such payment under its guaranty.
At December 31, 2004, the capitalization of SEGCO consisted of $59 million of equity and $88 million of debt on which the annual interest requirement is $3.2 million.
SEGCO paid dividends totaling $12.0 million in 2004,
$2.3 million in 2003, and $5.8 million in 2002, of which one-half of each was paid to the Company. In addition, the Company recognizes 50 percent of SEGCO's net income.
In addition to the Company's ownership of SEGCO, the Company's percentage ownership and investment in jointly-owned generating plants at December 31, 2004 is as follows:
In 2004, in order to avoid the loss of certain federal income tax credits related to the production of synthetic fuel, Southern Company chose to defer certain deductions otherwise available to the subsidiaries. The cash flow benefit associated with the utilization of the tax credits was allocated to the subsidiary that othervise would have claimed the available deductions on a separate company basis without the deferral. This allocation concurrently reduced the tax benefit of the credits allocated to those subsidiaries that generated the credits. As the deferred expenses are deducted, the benefit of the tax credits will be repaid to the subsidiaries that generated the tax credits.
The Company has recorded $21.4 million and $2.3 million payable to these subsidiaries in "Accumulated Deferred Income Taxes" and "Accrued Taxes - Income Tax",
respectively, on the balance sheets.
At December 31, 2004, the Company's tax-related regulatory assets and liabilities were $317 million and
$148 million, respectively. These assets are attributable to tax benefits flowed through to customers in prior years and to taxes applicable to capitalized interest. These liabilities are attributable to deferred taxes previously recognized at rates higher than the current enacted tax law and to unamortized investment tax credits.
Details of the income tax provisions are as follows:
Total Megawatt Company Facility (Type)
Capacity Ownership Greene County 500 60.00%
(coal)
Plant Miller Units I and 2 1,320 91.84%
(coal)
(1)
(2)
(I) Jointly owned with an affiliate, Mississippi Power.
(2) Jointly owned with Alabama Electric Cooperative, Inc.
Company Accumulated Facility Investment Depreciation (in millions)
Greene County
$114 S 56 Plant Miller Units I and 2 776 356 2004 2003 (in millions) 2002 Total provision for income taxes:
Federal --
Current Deferred S 44 219
$111 137 248
$209 41 250 263 The Company has contracted to operate and maintain the jointly owned facilities as agent for their co-owners.
The Company's proportionate share of its plant operating expenses is included in operating expenses in the statements of income.
State --
Current Deferred 16 34 50
$313 26 16 42
$290 35 7
42
$292 Total
- 5. INCOME TAXES Southern Company files a consolidated federal income tax return and a combined State of Georgia income tax return. Under a joint consolidated income tax allocation agreement, as required by the PUHCA, each subsidiary's current and deferred tax expense is computed on a stand-alone basis and no subsidiary is allocated more expense than would be paid if they filed a separate income tax return. In accordance with IRS regulations, each company is jointly and severally liable for the tax liability.
41
NOTES (continued)
Alabama Power Company 2004 Annual Report The tax effects of temporary differences between the carrying amounts of assets and liabilities in the financial statements and their respective tax bases, which give rise to deferred tax assets and liabilities, are as follows:
- 6. FINANCING Mandatorily Redeemable Preferred Securities/
Long-Term Debt Payable to Affiliated Trusts 2004 2003 (in millions)
Deferred tax liabilities:
Accelerated depreciation Property basis differences Premium on reacquired debt Pensions Fuel clause under recovered Other Total Deferred tax assets:
Federal effect of state deferred taxes State effect of federal deferred taxes Pole attachment rentals Unbilled revenue Pension and other benefits Fuel clause over recovered Other Total Total deferred tax liabilities, net Portion included in current (liabilities) assets, net Accumulated deferred income taxes in the balance sheets S 1,524 461 45 136 48 36 2.250
$ 1,319 466 46 128 29 1,988
_7_ _
112 110 45 22 16 32 337 100 98 27 23 15 2
72 337 The Company has formed certain wholly owned trust subsidiaries for the purpose of issuing preferred securities.
The proceeds of the related equity investments and preferred security sales were loaned back to the Company through the issuance of junior subordinated notes totaling
$309 million, which constitute substantially all assets of these trusts and are reflected on the balance sheets as Long-term Debt Payable to Affiliated Trusts. The Company considers that the mechanisms and obligations relating to the preferred securities issued for its benefit, taken together, constitute a full and unconditional guarantee by it of the respective trusts' payment obligations with respect to these securities. At December 31, 2004, preferred securities of $300 million were outstanding. See Note I under "Variable Interest Entities" for additional information on the accounting treatment for these trusts and the related securities.
First Mortgage Bonds The Company has a firm power sales contract with the Alabama Municipal Electric Authority (AMEA) entitling AMEA to scheduled amounts of capacity (up to a maximum 80 megawatts) for a period through October 2006. Under the terms of the contract, the Company received payments from AMEA representing the net present value of the revenues associated with the capacity entitlement, discounted at an effective annual rate of 11.19 percent. These payments are being recognized as operating revenues and the discount is amortized to other interest expense as scheduled capacity is made available over the terms of the contract.
1,913 1,651 (28) 34
$1,885
$1,685 In accordance with regulatory requirements, deferred investment tax credits are amortized over the lives of the related property with such amortization normally applied as a credit to reduce depreciation in the statements of income.
Credits amortized in this manner amounted to $11 million in each of 2004, 2003, and 2002. At December 31, 2004, all investment tax credits available to reduce federal income taxes payable had been utilized.
A reconciliation of the federal rate to the effective income tax rat
- 21 3
Federal statutory rate State income tax, net of federal deduction Non-deductible book depreciation Differences in prior years' deferred and current tax rates Other Effective income tax rate To secure AMEA's advance payments and the Company's performance obligation under the contracts, statutory ncome tax the Company issued and delivered to an escrow agent first e is as follows:
mortgage bonds representing the maximum amount of 004 2003 2002 liquidated damages payable by the Company in the event 5.0%/° 35.0% 35.0%
of a default under the contracts. No principal or interest is payable on such bonds unless and until a default by the 4.0 3.5 3.5 Company occurs. As the liquidated damages decline, a portion of the bond equal to the decrease is returned to the 1.1 1.2 1.3 Company. At December 31, 2004, S 18.7 million of these bonds were held by the escrow agent under the contract.
(U.8)
(1.0) 38.3'%o (U.9)
(1.6) 37.2%
(1.2)
(0.5) 38.1%
42
NOTES (continued)
Alabama Power Company 2004 Annual Report Pollution Control Bonds Bank Credit Arrangements Pollution control obligations represent installment purchases of pollution control facilities financed by funds derived from sales by public authorities of revenue bonds.
The Company is required to make payments sufficient for the authorities to meet principal and interest requirements of such bonds. With respect to $114.2 million of such pollution control obligations, the Company has authenticated and delivered to the trustees a like principal amount of first mortgage bonds as security for its obligations under the installment purchase agreements.
No principal or interest on these first mortgage bonds is payable unless and until a default occurs on the installment purchase agreements.
Senior Notes and Preferred Stock The Company issued a total of $900 million of unsecured senior notes and $ 100 million of preferred stock in 2004.
The proceeds of these issues were used to redeem or repay at maturity long-term debt, to repay short-term indebtedness, and for other general corporate purposes.
At December 31, 2004 and 2003, the Company had
$3.5 billion and $3.4 billion of senior notes outstanding, respectively. These senior notes are subordinate to all secured debt of the Company which amounted to approximately $286 million at December 31, 2004.
Long-Term Debt Due Within One Year A summary of the improvement fund requirements and scheduled maturities and redemptions of long-term debt due within one year at December 31 is as follows:
2004 2003 (in millions)
Capitalized leases
$ I Senior notes 225 525 Total
$225
$526 Debt serial maturities through 2009 applicable to total long-term debt are as follows: $225 million in 2005; $715 million in 2006; $500 million in 2007; S410 million in 2008; and $250 million in 2009.
Assets Subject to Lien The Company's mortgage, as amended and supplemented, securing the first mortgage bonds issued by the Company, constitutes a direct lien on substantially all of the Company's fixed property and franchises.
The Company maintains committed lines of credit in the amount of $868 million (including $504 million of such lines which are dedicated to funding purchase obligations relating to variable rate pollution control bonds), of which
$643 million will expire at various times during 2005.
$225 million of the credit facilities expiring in 2005 allow for the execution of term loans for an additional two-year period, and $245 million allow for the execution of one-year term loans. All of the credit arrangements require payment of a commitment fee based on the unused portion of the commitment or the maintenance of compensating balances with the banks. Commitment fees are less than 1/4 of I percent for the Company. Because the arrangements are based on an average balance, the Company does not consider any of its cash balances to be restricted as of any specific date. For syndicated credit arrangements, a fee is also paid to the agent banks.
Most of the Company's credit arrangements with banks have covenants that limit the Company's debt to 65 percent of total capitalization, as defined in the arrangements. For purposes of calculating these covenants, long-term notes payable to affiliated trusts are excluded from debt but included in capitalization.
Exceeding this debt level would result in a default under the credit arrangements. At December 31,2004, the Company was in compliance with the debt limit covenants. In addition, the credit arrangements typically contain cross default provisions that would be triggered if the Company defaulted on other indebtedness (including guarantee obligations) above a specified threshold. None of the arrangements contain material adverse change clauses at the time of borrowings.
The Company borrows through commercial paper programs that have the liquidity support of committed bank credit arrangements. In addition, the Company borrows from time to time through extendible commercial note programs. As of December 31, 2004 and 2003, the Company had no extendible commercial notes and no commercial paper outstanding. During 2004, the peak amount outstanding for commercial paper was S 190 million and the average amount outstanding was $41.5 million. The average annual interest rate on commercial paper in 2004 was 1.51 percent. Commercial paper and extendible commercial notes are included in notes payable on the balance sheets.
At December 31,2004, the Company had regulatory approval to have outstanding up to $1 billion of short-term borrowings.
43
NOTES (continued)
Alabama Power Company 2004 Annual Report Financial Instruments The Company enters into energy-related derivatives to hedge exposures to electricity, gas, and other fuel price changes. However, due to cost-based rate regulations, the Company has limited exposure to market volatility in commodity fuel prices and prices of electricity. The Company has implemented fuel-hedging programs at the instruction of the Alabama PSC. The Company also enters into hedges of forward electricity sales.
There was no material ineffectiveness recorded in earnings in 2004 and 2003.
At December 31, 2004, the fair value of derivative energy contracts was reflected in the financial statements as follows:
Amounts (in thousands)
$3,978 Regulatory liabilities, net Net income Total fair value 39
$4,017 The fair value gain or loss for cash flow hedges that are recoverable through the regulatory fuel clauses are recorded in the regulatory assets and liabilities and are recognized in earnings at the same time the hedged items affect earnings. The Company has energy-related hedges in place through 2007.
The Company also enters into derivatives to hedge exposure to changes in interest rates. Derivatives related to variable rate securities or forecasted transactions are accounted for as cash flow hedges. As the derivatives employed as hedging instruments are generally structured to match the critical terms of the hedged debt instruments, no material ineffectiveness has been recorded in earnings.
At December 31, 2004, the Company had S981 million notional amount of interest rate swaps outstanding with net fair value losses of $7.2 million as follows:
Cash Flow Hedges Weighted Average Fair Fixed Value Rate Notional Gain/
Maturity Paid Amount (Loss)
(in millions) 2006 1.89
$195
$3.2 2007 2.01*
536 5.6 2035 5.68 250 (16.0)
- Iledged using the Bond Market Association Municipal Swap Index.
The fair value gain or loss for cash flow hedges is recorded in other comprehensive income and is reclassified into earnings at the same time the hedged items affect earnings. In 2004 and 2003, the Company settled gains (losses) of S5.5 million and S(8) million, respectively, upon termination of certain interest derivatives at the same time it issued debt. These gains (losses) have been deferred in other comprehensive income and will be amortized to interest expense over the life of the original interest derivative, which approximates to the underlying related debt.
For the years 2004, 2003 and 2002, approximately
$6.3 million, $11.3 million, and $2.1 million, respectively, of pre-tax losses were reclassified from other comprehensive income to interest expense. For 2005, pre-tax gains of approximately $0.7 million are expected to be reclassified from other comprehensive income to interest expense. The Company has interest-related hedges in place through 2035.
- 7.
COM1M1ITMIENTS Construction Program The Company is engaged in continuous construction programs, currently estimated to total S902 million in 2005, $921 million in 2006, and $1.0 billion in 2007.
These amounts include $24 million, $12 million, and
$ 11 million in 2005, 2006, and 2007, respectively, for construction expenditures related to contractual purchase commitments for uranium and nuclear fuel conversion, enrichment, and fabrication services included under "Fuel Commitments." The construction programs are subject to periodic review and revision, and actual construction costs may vary from the above estimates because of numerous factors. These factors include: changes in business conditions; revised load growth estimates; changes in environmental regulations; changes in existing nuclear plants to meet new regulatory requirements; changes in FERC rules and transmission regulations; increasing costs of labor, equipment, and materials; and cost of capital. At December 31, 2004, significant purchase commitments were outstanding in connection with the construction program. The Company has no generating plants under construction. Construction of new transmission and distribution facilities and capital improvements, including those needed to meet environmental standards for existing generation, transmission, and distribution facilities, will continue.
44
NOTES (continued)
Alaibama Power Company 2004 Annual Report Long-Term Service Agreements Fuel Commitments The Company has entered into several Long-Term Service Agreements (LTSAs) with General Electric (GE) for the purpose of securing maintenance support for its combined cycle and combustion turbine generating facilities. The LTSAs stipulate that GE will perform all planned inspections on the covered equipment, which includes the cost of all labor and materials. GE is also obligated to cover the costs of unplanned maintenance on the covered equipment subject to a limit specified in each contract.
In general, these LTSAs are in effect through two major inspection cycles per unit. Scheduled payments to GE are made at various intervals based on actual operating hours of the respective units. Total payments to GE under these agreements for facilities owned are currently estimated at $253 million over the term of the agreements, which are approximately 12 to 14 years per unit. At December 31, 2004, the remaining balance was approximately $193 million. However, the LTSAs contain various cancellation provisions at the option of the Company.
Payments made to GE prior to the performance of any planned maintenance are recorded as either prepayments or other deferred charges and assets in the balance sheets. Inspection costs are capitalized or charged to expense based on the nature of the work performed.
Purchased Power Commitments The Company has entered into various long-term commitments for the purchase of electricity. Total estimated minimum long-term obligations at December 31, 2004 were as follows:
To supply a portion of the fuel requirements of its generating plants, the Company has entered into various long-term commitments for the procurement of fossil and nuclear fuel. In most cases, these contracts contain provisions for price escalations, minimum purchase levels, and other financial commitments. Coal commitments include forward contract purchases for sulfur dioxide emission allowances. Natural gas purchase commitments contain given volumes with prices based on various indices at the time of delivery. Amounts included in the chart below represent estimates based on New York Mercantile Exchange future prices at December 31, 2004.
Total estimated minimum long-term commitments at December 31, 2004 were as follows:
Natural Gas Coal &
Nuclear Fuel Year 2005 2006 2007 2008 2009 2010 and thereafter Total commitments
$249 195 114 26 26 108
$718 (in millions)
$ 907 804 713 225 131 97
$2,877 Additional commitments for fuel will be required to supply the Company's future needs.
SCS may enter into various types of wholesale energy and natural gas contracts acting as an agent for the Company and all of the other Southern Company retail operating companies, Southern Power, and Southern Company GAS. Under these agreements, each of the retail operating companies, Southern Power, and Southern Company GAS may be jointly and severally liable. The creditworthiness of Southern Power and Southern Company GAS is currently inferior to the creditworthiness of the retail operating companies. Accordingly, Southern Company has entered into keep-well agreements with the Company and each of the other retail operating companies to insure the Company will not subsidize or be responsible for any costs, losses, liabilities, or damages resulting from the inclusion of Southern Power or Southern Company GAS as a contracting party under these agreements.
Operating Leases Affiliate Year 2005 2006 2007 2008 2009 2010 and thereafter Total commitments
$ 50 50 50 50 50 13
$263 Commitments Non-d Affiliated (in millions)
$ 37 37 38 39 40 25
$216 Total
$ 87 87 88 89 90 38
$479 The Company has entered into rental agreements for coal rail cars, vehicles, and other equipment with various terms and expiration dates. These expenses totaled S28.3 45
NOTES (continued)
Alabama Power Company 2004 Annual Report million in 2004, $29.5 million in 2003, and $29.6 million in 2002. Of these amounts, $16.3 million, $19.4 million, and $19.1 million for 2004, 2003, and 2002, respectively, relates to the rail car leases and are recoverable through the Company's Rate ECR clause. At December 31, 2004, estimated minimum rental commitments for noncancellable operating leases were as follows:
maximum period of three years from the date of grant.
Options outstanding will expire no later than 10 years after the date of grant, unless terminated earlier by the Southern Company Board of Directors in accordance with the stock option plan. Activity from 2002 to 2004 for the options granted to the Company's employees under the stock option plan is summarized below:
Rail Vehicles Year Cars
& Other Total (in millions) 2005
$17.7
$11.4 S 29.1 2006 14.1 8.6 22.7 2007 6.9 5.7 12.6 2008 6.6 4.0 10.6 2009 4.8 3.6 8.4 2010 and thereafter 27.4 7.2 34.6 Total minimum payments
$77.5 S40.5 SI 18.0 In addition to the rental commitments above, the Company has potential obligations upon expiration of certain leases with respect to the residual value of the leased property. These leases expire in 2006 and 2009, and the Company's maximum obligations are $66 million and $19.5 million, respectively. At the termination of the leases, at the Company's option, the Company may negotiate an extension, exercise its purchase option, or the property can be sold to a third party. The Company expects that the fair market value of the leased property would substantially reduce or eliminate the Company's payments under the residual value obligations.
Guarantees At December 31, 2004, the Company had outstanding guarantees related to SEGCO's purchase of certain pollution control facilities and issuance of senior notes, as discussed in Note 4, and to certain residual values of leased assets. See "Operating Leases" above.
- 8. STOCK OPTION PLAN Balance at December 31, 2001 Options granted Options canceled Options exercised Balance at December 31, 2002 Options granted Options canceled Options exercised Balance at December 31, 2003 Options granted Options canceled Options exercised Balance at December 31. 2004 Shares Subject to Option 5,201,605 1,332,716 (12,515)
(827,883) 5,693,923 1,201,677 (6,726)
(1,043,013) 5,845,861 1,168,140 (3,379)
(1,252,277) 5,758,345 I
Average Option Price per Share S17.56 25.26 22.59 15.03 19.72 27.98 23.11 16.16 22.05 29.50 28.82 18.07 24.42 I
Options exercisable:
At December 31, 2002 2,702,614 At December31, 2003 3,171,383 At December31, 2004 3,404,264 The following table summarizes information about options outstanding at December 31, 2004:
Dollar Price Range of Options 13-20 20-26 26-32 Outstanding:
Shares (in thousands) 1,386 2,032 2,340 Average remaining life (inyears) 5.7 6.8 8.6 Average exercise price
$17.56 S24.12
$28.74 Exercisable:
Shares (in thousands) 1,386 1,609 409 Average exercise price
$17.56 S23.83
$28.00 Southern Company provides non-qualified stock options to a large segment of the Company's employees ranging from line management to executives. As of December 31, 2004, 1,111 current and former employees of the Company participated in this stock option plan. The maximum number of shares of Southern Company common stock that may be issued under the plan may not exceed 55 million. The prices of options granted to date have been at the fair market value of the shares on the dates of grant. Options granted to date become exercisable pro rata over a
- 9. NUCLEAR INSURANCE Under the Price-Anderson Amendments Act of 1988 (Act), the Company maintains agreements of indemnity with the NRC that, together with private insurance, cover third-party liability arising from any nuclear incident occurring at Plant Farley. The Act provides funds up to
$10.76 billion for public liability claims that could arise from a single nuclear incident. Plant Farley is insured against this liability to a maximum of $300 million by 46
NOTES (continued)
Alabama Power Company 2004 Annual Report American Nuclear Insurers (ANI), with the remaining coverage provided by a mandatory program of deferred premiums that could be assessed, after a nuclear incident, against all owners of nuclear reactors. The Company could be assessed up to $100.5 million per incident for each licensed reactor it operates but not more than an aggregate of $10 million per incident to be paid in a calendar year for each reactor. Such maximum assessment, excluding any applicable state premium taxes, for the Company is $201 million per incident but not more than an aggregate of $20 million to be paid for each incident in any one year. The Act expired in August 2002; however, the indemnity provisions of the act remain in place for commercial nuclear reactors.
The Company is a member of Nuclear Electric Insurance Limited (NEIL), a mutual insurer established to provide property damage insurance in an amount up to
$500 million for members' nuclear generating facilities.
Additionally, the Company has policies that currently provide decontamination, excess property insurance, and premature decommissioning coverage up to $2.25 billion for losses in excess of the $500 million primary coverage.
This excess insurance is also provided by NEIL.
NEIL also covers the additional costs that would be incurred in obtaining replacement power during a prolonged accidental outage at a member's nuclear plant.
Members can purchase this coverage, subject to a deductible waiting period of up to 26 weeks, with a maximum per occurrence per unit limit of $490 million.
After this deductible period, weekly indemnity payments would be received until either the unit is operational or until the limit is exhausted in approximately three years.
The Company purchases the maximum limit allowed by NEIL and has elected a 12 week waiting period.
NEIL aggregate, applies to non-certified claims stemming from terrorism within a 12 month duration, is $3.24 billion plus any amounts available through reinsurance or indemnity from an outside source. The non-certified ANI cap is a $300 million shared industry aggregate. Any act of terrorism that is certified pursuant to the TRIA will not be subject to the foregoing NEIL and ANI limitations but will be subject to the TRIA annual aggregate limitation of
$100 billion of insured losses arising from certified acts of terrorism. The TRIA will expire on December 31, 2005.
For all on-site property damage insurance policies for commercial nuclear power plants, the NRC requires that the proceeds of such policies shall be dedicated first for the sole purpose of placing the reactor in a safe and stable condition after an accident. Any remaining proceeds are to be applied next toward the costs of decontamination and debris removal operations ordered by the NRC, and any further remaining proceeds are to be paid either to the Company or to its bond trustees as may be appropriate under the policies and applicable trust indentures.
All retrospective assessments, whether generated for liability, property, or replacement power, may be subject to applicable state premium taxes.
- 10. QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
Summarized quarterly financial information for 2004 and 2003 are as follows:
Net Income After Dividends on Preferred Stock Quarter Ended Operating Operating Revenues Income (in millions)
Under each of the NEIL policies, members are subject to assessments if losses each year exceed the accumulated funds available to the insurer under that policy. The current maximum annual assessments for the Company under the NEIL policies would be $39 million.
Following the terrorist attacks of September 2001, both ANI and NEIL confirmed that terrorist acts against commercial nuclear power plants would be covered under their insurance. Both companies, however, revised their policy terms on a prospective basis to include an industry aggregate for all "non-certified" terrorist acts, (i.e., acts that are not certified acts of terrorism pursuant to the Terrorism Risk Insurance Act of 2002 (TRIA)). The March 2004 June 2004 September 2004 December 2004 March 2003 June 2003 September 2003 December 2003
$ 960 1,059 1,246 971
$ 890 950 1,216 904
$202 239 415 164
$211 227 414 163 S 91 104 220 66
$ 92 107 217 57 The Company's business is influenced by seasonal weather conditions.
47
SELECTED FINANCIAL AND OPERATING DATA 2000-2004 Alabama Plower Company 2004 Annual Report 2004 2003 2002 2001 2000 Operating Revenues (in thousands)
S4,235,991
$3,960,161
$3,710,533 S3,586,390 S3,667,461 Net Income after Dividends on Preferred Stock (in thousands)
$481,171
$472,810
$461,355
$386,729 S419,916 Cash Dividends on Common Stock (in thousands)
$437,300
$430,200
$431,000
$393,900 S417,100 Return on Average Common Equity (percent) 13.53 13.75 13.80 11.89 13.58 Total Assets (in thousands)
S12,783,459
$12,102,796
$11,591,666 SI 1,303,605 S11,228,118 Gross Property Additions (in thousands)
S797,014
$661,154
$645,262
$635,540 S870,581 Capitalization (in thousands):
Common stock equity
$3,610,204
$3,500,660
$3,377,740 S3,310,877
$3,195,772 Preferred stock 465,047 372,512 247,512 317,512 317,512 Mandatorily redeemable preferred securities 300,000 300,000 347,000 347,000 Long-term debt payable to affiliated trusts 309,279 Long-term debt 3,855,257 3,377,148 2,872,609 3,742,346 3,425,527 Total (excluding amounts due within one year)
S8,239,787
$7,550,320
$6,797,861 S7,717,735
$7.285,811 Capitalization Ratios (percent):
Common stock equity 43.8 46.4 49.7 42.9 43.9 Preferred stock 5.6 4.9 3.6 4.1 4.4 Mandatorily redeemable preferred securities 4.0 4.4 4.5 4.8 Long-term debt payable to affiliated trusts 3.8 Long-term debt 46.8 44.7 42.3 48.5 46.9 Total (excluding amounts due within one year) 100.0 100.0 100.0 100.0 100.0 Security Ratings:
First Mortgage Bonds -
Moody's Al Al Al Al Al Standard and Poor's A
A A
A A
Fitch AA-A+
A+
A+
AA-IPreferred Stock -
Moody's Baal Baal Baal Baal a2 Standard and Poor's BBB+
BBB+
BBB+
BBB+
BBB+
Fitch A
A-A-
A-A Unsecured Long-Term Debt -
Moody's A2 A2 A2 A2 A2 Standard and Poor's A
A A
A A
Fitch A+
A A
A A+
Customers (car-end):
Residential 1,170,814 1,160,129 1,148,645 1,139,542 1,132,410 Commercial 208,547 204,561 203,017 196,617 193,106 Industrial 5,260 5,032 4,874 4,728 4,819 Other 753 757 789 751 745 Total 1,385,374 1,370,479 1,357,325 1,341,638 1,331,080 Employees (year-end):
6,745 6,730 6,715 6,706 6,871 48
SELECTED FINANCIAL AND OPERATING DATA 2000-2004 (continued)
Alabama Power Company 2004 Annual Report 2004 2003 2002 2001 2000 Operating Revenues (in thousands):
Residential
$1,346,669 S1,276,800
$1,264,431
$1,138,499
$1,222,509 Commercial 980,771 913,697 882,669 829,760 854,695 Industrial 948,528 844,538 788,037 763,934 859,668 Other 16,860 16,428 16,080 15,480 15,835 Total retail 3,292,828 3,051,463 2,951,217 2,747,673 2,952,707 Sales for resale - non-affiliates 483,839 487,456 474,291 485,974 461,730 Sales for resale - affiliates 308,312 277,287 188,163 245,189 166,219 Total revenues from sales of electricity 4,084,979 3,816,206 3,613,671 3,478,836 3,580,656 Other revenues 151,012 143,955 96,862 107,554 86,805 Total
$4,235,991
$3,960,161 S3,710,533
$3,586,390
$3,667,461 Kilowatt-Hour Sales (in thousands):
Residential 17,368,321 16,959,566 17,402,645 15,880,971 16,771,821 Commercial 13,822,926 13,451,757 13,362,631 12,798,711 12,988,728 Industrial 22,854,399 21,593,519 21,102,568 20,460,022 22,101,407 Other 198,253 203,178 205,346 198,102 205,827 Total retail 54,243,899 52,208,020 52,073,190 49,337,806 52,067,783 Sales for resale - non-affiliates 15,483,420 17,085,376 15,553,545 15,277,839 14,847,533 Sales for resale - affiliates 7,233,880 9,422,301 8,844,050 8,843,094 5,369,474 Total 76,961,199 78,715,697 76,470,785 73,458,739 72,284,790 Average Revenue Per Kilowatt-Hour (cents):
Residential 7.75 7.53 7.27 7.17 7.29 Commercial 7.10 6.79 6.61 6.48 6.58 Industrial 4.15 3.91 3.73 3.73 3.89 Total retail 6.07 5.84 5.67 5.57 5.67 Sales for resale 3.49 2.88 2.72 3.03 3.11 Total sales 5.31 4.85 4.73 4.74 4.95 Residential Average Annual Kilowatt-Hour Use Per Customer 14,894 14,688 15,198 13,981 14,875 Residential Average Annual Revenue Per Customer
$1,155
$1,106
$1,104
$1,002
$1,084 Plant Nameplate Capacity Ratings (year-end)(mCgawatts) 12,216 12,174 12,153 12,153 12,122 Maximum Peak-Hour Demand (megawatts):
Winter 9,556 10,409 9,423 9,300 9,478 Summer 10,938 10,462 10,910 10,241 11,019 Annual Load Factor (percent) 63.2 64.1 62.9 62.5 59.3 Plant Availability (percent):
Fossil-steam 87.8 85.9 85.8 87.1 89.4 Nuclear 88.7 94.7 93.2 83.7 88.3 Source of Energy Supply (percent):
Coal 56.5 56.5 55.5 56.8 63.0 Nuclear 16.4 17.0 17.1 15.8 16.9 Hydro 5.6 7.0 5.1 5.1 2.9 Gas 8.9 7.6 11.6 10.7 4.9 Purchased power -
From non-affiliates 5.4 4.1 4.0 4.4 4.6 From affiliates 7.2 7.8 6.7 7.2 7.7 Total 100.0 100.0 100.0 100.0 100.0 49
-1' DIRECTORS AND OFFICERS Alabama Poi, er Company 2004 An nual Report Directors WVhit Armstrong President, Chairman and CEO, Thle Citizens Bank David J. Cooper, Sr.
President, Cooper/T. Smith Corporation 1I. Allen Franklin' Chairman, President and CEO, Southern Company R. Kent Hlenslee Managing Partner, Flenslee, Robertson, Strawn &
Knowles, L.L.C.
John D. Johns Chairman, President and CEO, Protective Life Corporation Carl E. Jones, Jr.
Chairman and CEO, Regions Financial Corporation Patricia MI. King President and CEO, Sunny King Automotive Group James K. Lowder
- Chairman, The Colonial Company Wallace D. Malone, Jr.
Vice Chairman, Wachovia Corporation Charles D. McCrary President and CEO, Alabama Power Company Dr. Malcolm Portera Chancellor, The University of Alabama System Robert D. Powers President, The Eufaula Agency David M\\. Ratcliffe2 Chairman, President and CEO, Southern Company C. Dowd Ritter Chairman, President and CEO, AmSouth Bancorporation James II. Sanford Chainnan, HOME Place Farms, Inc.
John Cox Webb, IV President, Webb Lumber Company, Inc.
James WV.
Wright Chairman, President and CEO, First Tuskegee Bank Officers Charles D.,MlcCrary President and Chief Executive Officer Villiam B. IHutchins, 1113 Executive Vice President, Chief Financial Officer and Treasurer Art P. Beattie 4 Executive Vice President, Chief Financial Officer and Treasurer C. Alan Martin Executive Vice President Steve IL Spencer Executive Vice President Rodney 0. M1undy Senior Vice President and Counsel Robert Holmes, Jr.
Senior Vice President Robin A. Hurst Senior Vice President Michael L. Scott Senior Vice President Jerry L. Stewart Senior Vice President Philip C. Raymond5 Vice President and Comptroller William E. Zales, Jr.
Vice President, Corporate Secretary and Assistant Treasurer Christopher T. Bell Vice President Willard L Bowers Yice President Larry R. Grill Vice President Donald It. Ilorsley6 Vice President Gerald L. Johnson Vice President, Birmingham Division Marsha S. Johnson7 Vice President, Birmingham Division Villiam B. Johnson Vice President Barbara J. Knight Vice President Ellen N. Lindemann Vice President Gordon G. Martin Vice President, Southern Division M1yrna J. Pittmang Vice President Donald WV.
Reese Vice President R.N Michael Saxon Vice President, Southeast Division Julia hI. Segars Vice President Julian 11. Smith, Jr.
Vice President V. Ronald Smith Vice President, Eastern Division Zeke WV.
Smith9 Vice President Cheryl A. Thompson Vice President, Mobile Division Terry 11. Waters Vice President, Western Division E. Wayne Boston Assistant Secretary and Assistant Treasurer J. Randy DeRieux Assistant Treasurer Robert Cole Giddens Assistant Comptroller Ceila 11. Shorts Assistant Secretary Kay 1. Worley Assistant Secretary All information as of December31, 2004 except as noted below
'Resigned 7/04 2 Elected 7/04 3 Retired 2/05 4 Elected 2/05 5 Elected 2/05 6 Elected 3/05 7Resigned 2/05 s Elected 2/05 9 Elected 2/05 50
CORPORATE INFORMATION Alabama Power Company 2004 Annual Report General This annual report is submitted for general information and is not intended for use in connection with any sale or purchase of, or any solicitation of offers to buy or sell securities.
Profile The Company operates as a vertically integrated utility providing electricity to retail customers within its traditional service area located within the State of Alabama and to wholesale customers in the Southeast. The Company sells electricity to almost 1.4 million customers within its service area of approximately 45,000 square miles. In 2004, retail energy sales accounted for 70 percent of the Company's total sales of 77.0 billion kilowatt-hours.
The Company is a wholly owned subsidiary of The Southern Company, which is the parent company of five retail operating companies. There is no established public trading market for the Company's common stock.
Trustee, Registrar and Interest Paying Agent All series of First Mortgage Bonds, Senior Notes and Trust Preferred Securities JPMorgan Chase Bank, N.A.
Institutional Trust Services 4 New York Plaza, 15'h Floor New York, NY 10004 The Flexible Money Market and 5.30% Series Class A Preferred Stock The Bank of New York 101 Barclay Street New York, NY 10286 Number of Preferred Shareholders of record as of December 31, 2004, was 1,766.
Form 10-K A copy of the Form 10-K as filed with the Securities and Exchange Commission will be provided upon written request to the office of the Corporate Secretary. For additional information, contact the office of the Corporate Secretary at (205) 257-3385.
Alabama Power Company 600 North 18t Street Birmingham, AL 35291 (205) 257-1000 www.alabamapower.com Auditors Deloitte & Touche LLP 417 North 20th Street Suite 1000 Birmingham, AL 35203 Legal Counsel Balch & Bingham LLP P.O. Box 306 Birmingham, AL 35201 Registrar, Transfer Agent and Dividend Paying Agent All series except the Flexible Money Market and 5.30% Series Class A Preferred Stock Southern Company Services, Inc.
Stockholder Services P.O. Box 54250 Atlanta, GA 30308-0250 (800) 554-7626 51