EXHIBIT 99
MANAGEMENT'S REPORT
Georgia Power Company 2001 Annual Report
The management of Georgia Power Company has prepared this annual report and is
responsible for the financial statements and related information. These
statements were prepared in accordance with accounting principles generally
accepted in the United States and necessarily include amounts that are based on
the best estimates and judgments of management. Financial information throughout
this annual report is consistent with the financial statements.
The Company maintains a system of internal accounting controls to provide
reasonable assurance that assets are safeguarded and that the accounting records
reflect only authorized transactions of the Company. Limitations exist in any
system of internal controls based upon the recognition that the cost of the
system should not exceed its benefits. The Company believes that its system of
internal accounting controls maintains an appropriate cost/benefit relationship.
The Company's system of internal accounting controls is evaluated on an
ongoing basis by the Company's internal audit staff. The Company's independent
public accountants also consider certain elements of the internal control system
in order to determine their auditing procedures for the purpose of expressing an
opinion on the financial statements.
The audit committee of the board of directors, which is composed of three
independent directors, provides a broad overview of management's financial
reporting and control functions. At least three times a year this committee
meets with management, the internal auditors, and the independent public
accountants to ensure that these groups are fulfilling their obligations and to
discuss auditing, internal control and financial reporting matters. The internal
auditors and the independent public accountants have access to the members of
the audit committee at any time.
Management believes that its policies and procedures provide reasonable
assurance that the Company's operations are conducted with a high standard of
business ethics.
In management's opinion, the financial statements present fairly, in all
material respects, the financial position, results of operations and cash flows
of Georgia Power Company in conformity with accounting principles generally
accepted in the United States.
/s/David M. Ratcliffe
David M. Ratcliffe
President and Chief Executive Officer
/s/Thomas A. Fanning
Executive Vice President, Treasurer
and Chief Financial Officer
February 13, 2002
1
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To Georgia Power Company:
We have audited the accompanying balance sheets and statements of capitalization
of Georgia Power Company (a Georgia corporation and a wholly owned subsidiary of
Southern Company) as of December 31, 2001 and 2000, 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, 2001. These financial
statements are the responsibility of the 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 auditing standards generally
accepted in the United States. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the financial statements
are free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements.
An audit also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.
In our opinion, the financial statements (pages 13-33) referred to above
present fairly, in all material respects, the financial position of Georgia
Power Company as of December 31, 2001 and 2000, and the results of its
operations and its cash flows for each of the three years in the period ended
December 31, 2001, in conformity with accounting principles generally accepted
in the United States.
As explained in Note 1 to the financial statements, effective January 1,
2001, Georgia Power Company changed its method of accounting for derivative
instruments and hedging activities.
/s/Arthur Andersen LLP
Atlanta, Georgia
February 13, 2002
2
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL
CONDITION
Georgia Power Company 2001 Annual Report
RESULTS OF OPERATIONS
Earnings
Georgia Power Company's 2001 earnings totaled $610 million, representing a $51
million (9.1 percent) increase over 2000. Although operating income is lower due
to the impact of mild weather on retail revenues, overall net income improved
due to lower financing costs and non-operating expenses and a lower effective
tax rate resulting from various factors including property donations and
positive resolution of outstanding tax issues. The Company's 2000 earnings
totaled $559 million, representing an $18 million (3.3 percent) increase over
1999. This earnings increase was primarily due to higher retail and wholesale
sales and continued control of operating expenses, partially offset by
additional accelerated amortization of regulatory assets allowed under the
second year of a Georgia Public Service Commission (GPSC) three-year retail rate
order.
Revenues
Operating revenues in 2001 and the amount of change from the prior year are as
follows:
Increase
(Decrease)
From Prior Year
Amount -------------------
2001 2001 2000
---- -------------------
Retail - (in millions)
Base revenues $3,102 $(17) $ 84
Fuel cost recovery 1,247 49 183
- -------------------------------------------------------------------
Total retail 4,349 32 267
- -------------------------------------------------------------------
Sales for resale -
Non-affiliates 366 68 88
Affiliates 100 4 20
- -------------------------------------------------------------------
Total sales for resale 466 72 108
- -------------------------------------------------------------------
Other operating revenues 151 (9) 39
- -------------------------------------------------------------------
Total operating revenues $4,966 $95 $414
===================================================================
Percent change 2.0% 9.3%
- -------------------------------------------------------------------
Retail base revenues of $3.1 billion in 2001 decreased $17 million (0.5
percent) from 2000 primarily due to a 2.5 percent decrease in retail sales from
the prior year. Milder-than-normal weather and a slowdown in the economy
contributed to the decline in such sales. Retail base revenues of $3.1 billion
in 2000 increased $84 million (2.8 percent) from 1999 primarily due to a 4.9
percent increase in sales. Under the prior GPSC retail rate order, the Company
recorded $44 million of revenue subject to refund for estimated earnings above
12.5 percent retail return on common equity in 2000. These refunds were made to
customers in 2001. See Note 3 to the financial statements under "Retail Rate
Orders" for additional information.
Electric rates include provisions to adjust billings for fluctuations in
fuel costs, the energy component of purchased power costs, and certain other
costs. Under these fuel cost recovery provisions, fuel revenues generally equal
fuel expenses -- including the fuel component of purchased energy -- and do not
affect net income. However, cash flow is affected by the untimely recovery of
these receivables. As of December 31, 2001, the Company had $162 million in
underrecovered fuel costs. The Company is currently collecting these
underrecovered fuel costs under a GPSC rate order issued on May 24, 2001. The
fuel cost recovery rate was increased effective June 2001 to allow for a
24-month recovery of the deferred underrecovered fuel costs.
Wholesale revenues from sales to non-affiliated utilities increased in 2001
and 2000 as follows:
2001 2000 1999
-----------------------------
(in millions)
Long-term contracts $ 61 $ 55 $ 55
Other sales 305 243 155
- -------------------------------------------------------------
Total $366 $298 $210
=============================================================
Revenues from long-term contracts increased slightly in 2001 due to
increased energy sales while remaining constant in 2000. See Note 7 to the
financial statements for further information regarding these sales. Revenues
from other non-affiliated sales increased $62 million (25.5 percent) primarily
due to increases in off-system sale transactions that were generally offset by
corresponding purchase transactions. These transactions had no significant
effect on income.
Revenues from sales to affiliated companies within the Southern 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 transactions do not have a significant impact on earnings.
Other operating revenues in 2001 decreased $9 million (5.3 percent)
primarily due to lower gains on the sale of generating plant emission
allowances, partially offset by increased revenues from the transmission of
electricity and from the rental of electric equipment and property. Other
3
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 2001 Annual Report
operating revenues in 2000 increased $39 million (33 percent) primarily due to
increased revenues from the transmission of electricity and gains on the sale of
generating plant emission allowances. Under a GPSC order, $28 million of the
gains on emission allowance sales in 2000 were used to reduce recoverable fuel
costs and, as such, did not affect earnings.
Kilowatt-hour (KWH) sales for 2001 and the percent change by year were as
follows:
Percent Change
----------------------
2001
KWH 2001 2000
--------- ------------------------
(in billions)
Residential 20.1 (2.8)% 6.6%
Commercial 26.5 3.4 8.1
Industrial 25.4 (8.0) 0.9
Other 0.6 2.5 3.2
------
Total retail 72.6 (2.5) 4.9
------
Sales for resale -
Non-affiliates 8.1 25.5 27.7
Affiliates 3.1 28.7 35.6
------
Total sales for resale 11.2 26.3 29.8
------
Total sales 83.8 0.5 7.1
======
- ------------------------------------------------------------
Residential sales decreased 2.8 percent due to milder-than-normal weather.
Commercial sales increased 3.4 percent due to a 2.8 percent increase in
customers, while industrial sales decreased 8.0 percent due to an economic
slowdown. Residential and commercial sales increased 6.6 percent and 8.1
percent, respectively, in 2000 due to warmer summer temperatures and colder
winter weather. Strong regional economic growth was also a factor in the
increase in commercial sales. Industrial sales remained fairly constant.
Expenses
Fuel costs constitute the single largest expense for the Company. The mix of
fuel sources for generation of electricity is determined primarily by system
load, the unit cost of fuel consumed, and the availability of hydro and nuclear
generating units. The amount and sources of generation and the average cost of
fuel per net KWH generated were as follows:
2001 2000 1999
--------------------------
Total generation
(billions of KWH) 68.9 73.6 69.3
Sources of generation
(percent) --
Coal 74.9 75.8 75.5
Nuclear 23.2 21.2 21.6
Hydro 1.4 0.8 1.0
Oil and gas 0.5 2.2 1.9
Average cost of fuel per net
KWH generated
(cents) -- 1.38 1.39 1.34
- --------------------------------------------------------------
Fuel expense decreased 7.7 percent due to a decrease in generation because
of lower energy demands and a slightly lower average cost of fuel. Fuel expense
increased 10.7 percent in 2000 due to an increase in generation to meet higher
energy demands, a decrease in generation from hydro plants, and a higher average
cost of fuel.
Purchased power expense increased $175 million (29.4 percent) in 2001
primarily due to an increase in off-system purchases used to meet off-system
sales commitments. These transactions had no significant effect on earnings.
Purchased power expense in 2000 increased $206 million (53 percent) over the
prior year due to higher retail energy demands and off-system purchase
transactions used to meet off-system sales transactions.
In 2001, other operation and maintenance expenses increased $41 million
(3.4%) due to additional severance costs, increased scheduled generating plant
maintenance, and higher uncollectible account expense. Other operation and
maintenance expenses in 2000 increased slightly over those in 1999. Increased
line maintenance, customer assistance and sales expense, and severance costs
were partially offset by decreased generating plant maintenance and decreased
employee benefit provisions.
Depreciation and amortization decreased $19 million in 2001 primarily due
to lower accelerated amortization under the third year of a GPSC retail rate
order. Depreciation and amortization increased $66 million in 2000 primarily due
to $50 million of additional accelerated amortization of regulatory assets
required under the second year of the GPSC retail rate order and increased plant
in service.
4
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 2001 Annual Report
Other, net increased in 2001 due to gains realized on sales of assets and a
decrease in charitable contributions. Other, net decreased in 2000 due to an
increase in charitable contributions.
Interest expense, net decreased in 2001 primarily due to lower interest
rates that offset new financing costs. Interest expense, net increased in 2000
due to the issuance of additional senior notes during 2000. The Company
refinanced or retired $775 million and $179 million of securities in 2001 and
2000, respectively. Distributions on preferred securities of subsidiary
companies remained unchanged in 2001 and decreased $7 million in 2000 due to the
redemption of $100 million of preferred securities in December 1999.
Effects of Inflation
The Company is subject to rate regulation and income tax laws that are based on
the recovery of 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 plants 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.
FUTURE EARNINGS POTENTIAL
General
The results of operations for the past three years are not necessarily
indicative of future earnings. The level of future earnings depends on numerous
factors including regulatory matters and energy sales.
Growth in energy sales is subject to a number of factors which
traditionally have included changes in contracts with neighboring utilities,
energy conservation practiced by customers, the elasticity of demand, weather,
competition, initiatives to increase sales to existing customers, and the rate
of economic growth in the Company's service area.
In accordance with Financial Accounting Standards Board (FASB) Statement
No. 87, Employers' Accounting for Pensions, the Company recorded non-cash income
of approximately $60 million in 2001. Future pension income is dependent on
several factors including trust earnings and changes to the plan. For the
Company, pension income is a component of the regulated rates and does not have
a significant effect on net income. For additional information, see Note 2 to
the financial statements.
The Company currently operates as a vertically integrated utility providing
electricity to customers within its traditional service area located in the
State of Georgia. Prices for electricity provided by the Company to retail
customers are set by the GPSC under cost-based regulatory principles.
On December 20, 2001, the GPSC approved a new three-year retail rate order
for the Company ending December 31, 2004. Under the terms of the order, earnings
will be evaluated annually against a retail return on common equity range of 10
percent to 12.95 percent. Two-thirds of any earnings above the 12.95 percent
return will be applied to rate refunds, with the remaining one-third retained by
the Company. Retail rates were decreased by $118 million effective January 1,
2002. Pursuant to a previous three-year accounting order, the Company recorded
$336 million of accelerated cost amortization and interest thereon which has
been credited to a regulatory liability account as mandated by the GPSC. Under
the new rate order, the accelerated amortization and the interest will be
amortized equally over three years as a credit to expense beginning in 2002. The
Company will not file for a general base rate increase unless its projected
retail return on common equity falls below 10 percent. Georgia Power is required
to file a general rate case on July 1, 2004, in response to which the GPSC would
be expected to determine whether the rate order should be continued, modified,
or discontinued. See Note 3 to the financial statements under "Retail Rate
Orders" for additional information.
The Company has entered into power purchase agreements which will result in
higher capacity and operating and maintenance payments in future years. Under
the new retail rate order, these costs will be reflected in rates evenly over
the next three years. See Note 4 to the financial statements under "Purchased
Power Commitments" for additional information.
5
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 2001 Annual Report
Georgia Power had three new generation projects under construction during
2001. They included two units at Plant Dahlberg, a ten-unit, 800 megawatt
combustion turbine facility; two combined cycle units totaling 1,132 megawatts
at Plant Wansley; and Plant Goat Rock, a two-unit, 1,181 megawatt combined cycle
facility. All three of these projects have been transferred to Southern Power
Company, a new Southern Company subsidiary formed in 2001 to construct, own, and
manage wholesale generating assets in the Southeast. The ten Dahlberg units and
two Goat Rock units were transferred in 2001 and the transfer of the two Wansley
units was completed in January 2002.
The Company is involved in various matters being litigated. See Note 3 to
the financial statements for information regarding material issues that could
possibly affect future earnings.
Compliance costs related to current and future environmental laws,
regulations, and litigation could affect earnings if such costs are not fully
recovered. See "Environmental Issues" for further discussion of these matters.
Industry Restructuring
The electric utility industry in the United States is continuing to evolve as a
result of regulatory and competitive factors. Among the primary agents of change
has been the Energy Policy Act of 1992 (Energy Act). The Energy Act allows
independent power producers (IPPs) to access a utility's transmission network in
order to sell electricity to other utilities. This enhances the incentive for
IPPs to build cogeneration plants for a utility's large industrial and
commercial customers and sell energy generation to other utilities. Also,
electricity sales for resale rates are affected by wholesale transmission access
and numerous potential new energy suppliers, including power marketers and
brokers.
Although the Energy Act does not permit retail customer access, it has been
a major catalyst for recent restructuring and consolidations taking place within
the utility industry. Numerous federal and state initiatives are in varying
stages that promote wholesale and retail competition. Among other things, these
initiatives allow customers to choose their electricity provider. Some states
have approved initiatives that result in a separation of the ownership and/or
operation of generating facilities from the ownership and/or operation of
transmission and distribution facilities. While restructuring and competition
initiatives have been discussed in Georgia, none have been enacted. Enactment
would require numerous issues to be resolved, including significant ones
relating to recovery of any stranded investments, full cost recovery of energy
produced, and other issues related to the energy crisis that occurred in
California. As a result of that crisis, many states have either discontinued or
delayed implementation of initiatives involving retail deregulation. The Company
does compete with other electric suppliers within the state. In Georgia, most
new retail customers with at least 900 kilowatts of connected load may choose
their electricity supplier.
In December 1999, the Federal Energy Regulatory Commission (FERC) issued
its final rule on Regional Transmission Organizations (RTOs). The order
encouraged utilities owning transmission systems to form RTOs on a voluntary
basis. Southern Company has submitted a series of status reports informing the
FERC of progress toward the development of a Southeastern RTO. In these status
reports, Southern Company explained that it is developing an RTO known as
SeTrans with a number of non-jurisdictional cooperative and public power
entities. Recently, Entergy Corporation and Cleco Power joined the SeTrans
development process. In January 2002, the sponsors of SeTrans held a public
meeting to form a Stakeholder Advisory Committee, which will participate in the
development of the RTO. Southern Company continues to work with the other
sponsors to develop the SeTrans RTO. The creation of SeTrans is not expected to
have a material impact on Georgia Power's financial statements. The outcome of
this matter cannot now be determined.
Accounting Policies
Critical Policy
Georgia Power's significant accounting policies are described in Note 1 to the
financial statements. The Company's most critical accounting policy involves
rate regulation. The Company is subject to the provisions of FASB Statement No.
71, Accounting for the Effects of Certain Types of Regulation. In the event that
a portion of the Company's operations is no longer subject to these provisions,
the Company would be required to write off related regulatory assets and
liabilities that are not specifically recoverable, and determine if any other
assets, including plant, have been impaired. See Note 1 to the financial
statements under "Regulatory Assets and Liabilities" for additional information.
6
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 2001 Annual Report
New Accounting Standards
Effective January 2001, Georgia Power adopted FASB Statement No. 133, Accounting
for Derivative Instruments and Hedging Activities, as amended. Statement No. 133
establishes accounting and reporting standards for derivative instruments and
for hedging activities. This statement requires that certain derivative
instruments be recorded in the balance sheet as either an asset or liability
measured at fair value, and that changes in the fair value be recognized
currently in earnings unless specific hedge accounting criteria are met. See
Note 1 to the financial statements under "Financial Instruments" for additional
information. The impact on net income in 2001 was not material. An additional
interpretation of Statement No. 133 will result in a change -- effective April
1, 2002 -- in accounting for certain contracts related to fuel supplies that
contain quantity options. These contracts will be accounted for as derivatives
and marked to market. However, due to the existence of specific cost-based fuel
recovery clauses for the Company, this change is not expected to have a material
impact on net income.
In June 2001, the FASB issued Statement No. 142, Goodwill and Other
Intangible Assets, which establishes new accounting and reporting standards for
acquired goodwill and other intangible assets and supersedes Accounting
Principles Board Opinion No. 17. Statement No. 142 addresses how intangible
assets that are acquired individually or with a group of other assets (but not
those acquired in a business combination) should be accounted for upon
acquisition and on an ongoing basis. Goodwill and intangible assets that have
indefinite useful lives will not be amortized but rather will be tested at least
annually for impairment. Intangible assets that have finite useful lives will
continue to be amortized over their useful lives, which are no longer limited to
40 years. The Company adopted Statement No. 142 effective January 1, 2002 with
no material impact on the Company's financial statements.
Also, in June 2001, the FASB issued Statement No. 143, Asset Retirement
Obligations, which establishes new accounting and reporting standards for legal
obligations associated with retiring assets, including decommissioning nuclear
plants. The liability for an asset's future retirement must be recorded in the
period in which the liability is incurred. The cost must be capitalized as part
of the related long-lived asset and depreciated over the asset's useful life.
Changes in the liability resulting from the passage of time will be recognized
as operating expenses. Statement No. 143 must be adopted by January 1, 2003. The
Company has not yet quantified the impact of adopting Statement No. 143 on its
financial statements.
FINANCIAL CONDITION
Plant Additions
In 2001, gross utility plant additions were $1.4 billion. These additions were
primarily related to transmission and distribution facilities, the purchase of
nuclear fuel, and the construction of additional combustion turbine and combined
cycle units. The funds needed for gross property additions are currently
provided from operations, short-term and long-term debt, and capital
contributions from Southern Company. The Statements of Cash Flows provide
additional details.
Credit Rating Risk
The Company does not have any credit agreements that would require material
changes in payment schedules or terminations as a result of a credit rating
downgrade. There are certain physical electricity sale contracts that could
require collateral -- but not termination -- in the event of a credit rating
change to below investment grade. At December 31, 2001, the maximum potential
collateral requirements were approximately $112 million.
Exposure to Market Risks
The Company is exposed to market risks, including changes in interest rates,
currency exchange rates, and certain commodity prices. 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 hedging practices. Company policy is that derivatives
are to be used primarily for hedging purposes. Derivative positions are
monitored using techniques that include market valuation and sensitivity
analysis.
The Company's market risk exposures relative to interest rate changes have
not changed materially compared to the previous reporting period. In addition,
the Company is not aware of any facts or circumstances that would significantly
affect such exposures in the near term.
7
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 2001 Annual Report
If the Company sustained a 100 basis point change in interest rates for all
variable rate long-term debt, the change would affect annualized interest
expense by approximately $13 million at December 31, 2001. Based on the
Company's overall interest rate exposure at December 31, 2001, including
derivative and other interest rate sensitive instruments, a near-term 100 basis
point change in interest rates would not materially affect the Company's
financial statements.
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 mitigate residual risks relative to movements in electricity
prices, the Company entered into fixed price contracts for the purchase and sale
of electricity through the wholesale electricity market and to a lesser extent
similar contracts for gas purchases. Realized gains and losses are recognized in
the Statements of Income as incurred. At December 31, 2001, exposure from these
activities was not material to the Company's financial statements. Fair value of
changes in energy trading contracts and year-end valuations are as follows:
Changes During the Year
- ----------------------------------------------------
Fair Value
- ----------------------------------------------------
(in millions)
Contracts beginning of year $0.9
Contracts realized or settled (0.6)
New contracts at inception -
Changes in valuation techniques -
Current period changes 0.1
- ----------------------------------------------------
Contracts end of year $0.4
===================================================
All of these contracts are actively quoted and mature within one year. For
additional information, see Note 1 to the financial statements under "Financial
Instruments."
Financing Activities
In 2001, the Company's financing costs decreased due to lower interest rates
despite the issuance of new debt during the year. New issues during 1999 through
2001 totaled $1.9 billion and retirement or repayment of higher-cost securities
totaled $1.7 billion.
The proceeds from assets transferred to Southern Power were used to reduce
short-term debt and return capital to the Southern Company that was used during
the construction of these projects.
Composite financing rates for long-term debt, preferred stock, and
preferred securities for the years 1999 through 2001, as of year-end, were as
follows:
2001 2000 1999
--------------------------------
Composite interest rate
on long-term debt 4.26% 5.90% 5.48%
Composite preferred
stock dividend rate 4.60 4.60 4.60
Composite preferred
securities dividend rate 7.49 7.49 7.49
- ----------------------------------------------------------------
Liquidity and Capital Requirements
Cash provided from operations remained constant in 2001.
The Company estimates that construction expenditures for the years 2002
through 2004 will total $1.0 billion, $0.8 billion, and $0.8 billion,
respectively. Investments primarily in additional transmission and distribution
facilities and equipment to comply with environmental requirements are planned.
Cash requirements for redemptions announced and maturities of long-term
debt are expected to total $666 million during 2002 through 2004.
As a result of requirements by the Nuclear Regulatory Commission, the
Company has established external trust funds for the purpose of funding nuclear
decommissioning costs. The amount to be funded under the new GPSC rate order is
$8.7 million each year in 2002, 2003, and 2004. For additional information
concerning nuclear decommissioning costs, see Note 1 to the financial statements
under "Depreciation and Nuclear Decommissioning."
Sources of Capital
The Company expects to meet future capital requirements primarily using funds
generated from operations and equity funds from Southern Company and by the
issuance of new debt and equity securities, term loans, and short-term
borrowings. The Company plans to request new financing authority from the GPSC
in early 2002 to allow for the issuance of new long-term securities. To meet
short-term cash needs and contingencies, the Company had approximately $1.8
billion of unused credit arrangements with banks at the beginning of 2002. See
Note 9 to the financial statements under "Bank Credit Arrangements" for
additional information.
8
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 2001 Annual Report
The Company may also meet short-term cash needs through a Southern Company
subsidiary organized to issue and sell commercial paper at the request and for
the benefit of the Company and the other Southern Company operating companies.
At December 31, 2001, the Company had outstanding $707.6 million of commercial
paper.
Recently, the Company has relied on the issuance of unsecured debt and
trust preferred securities, in addition to unsecured pollution control bonds
issued for its benefit by public authorities, to meet its long-term external
financing requirements. In years past, the Company issued first mortgage bonds,
mortgage backed pollution control bonds and preferred stock to fund its external
requirements. The amount outstanding of these securities has been steadily
declining during the last four years.
Other Capital Requirements
In addition to the funds needed for the construction program, approximately $666
million will be required by the end of 2004 for maturities of long-term debt.
Also, the Company will continue to retire higher-cost debt and preferred
securities and replace these obligations with lower-cost capital if market
conditions permit.
These capital requirements, lease obligations, and purchase commitments --
discussed in Notes 4 and 9 to the financial statements -- are as follows:
2002 2003 2004
- ---------------------------------------------------------------
(in millions)
Bonds -
First mortgage $ 2 $ - $ -
Pollution control 8 - -
Notes 300 350 -
Leases -
Capital 2 2 2
Operating 15 15 15
Purchase commitments
Fuel 1,234 1,115 617
Purchased power 163 223 278
- ---------------------------------------------------------------
At the beginning of 2002, Georgia Power had not used any of its available
credit arrangements. Credit arrangements are as follows:
Expires
----------------------------
Total Unused 2002 2003 & beyond
------------------------------------------------------
(in millions)
$1,765 $1,765 $1,265 $500
------------------------------------------------------
ENVIRONMENTAL ISSUES
Clean Air Legislation
In November 1990, the Clean Air Act Amendments of 1990 (Clean Air Act) were
signed into law. Title IV of the Clean Air Act -- the acid rain compliance
provision of the law -- significantly affected Southern Company's subsidiaries,
including the Company. Reductions in sulfur dioxide and nitrogen oxide emissions
from fossil-fired generating plants were required in two phases. Phase I
compliance began in 1995.
Southern Company's subsidiaries, including the Company, achieved Phase I
compliance at the affected units by primarily switching to low-sulfur coal and
with some equipment upgrades. Construction expenditures for the Company's Phase
I compliance totaled approximately $167 million.
Phase II sulfur dioxide compliance was required in 2000. Southern Company's
subsidiaries, including the Company, used emission allowances and fuel switching
to comply with Phase II requirements. Also, equipment to control nitrogen oxide
emissions was installed on additional system fossil-fired units as necessary to
meet Phase II limits and ozone non-attainment requirements for metropolitan
Atlanta through 2000. Compliance for Phase II and initial ozone non-attainment
requirements increased total construction expenditures for the Company through
2000 by approximately $39 million.
In 2000, the State of Georgia established new emission limits designed to
help bring the Atlanta area into compliance with the national one-hour standard
for ground-level ozone. The limits include new emission standards for seven of
the Company's generating stations and will go into effect in May 2003.
Construction expenditures for the Company's compliance with these new rules are
currently estimated at approximately $699 million with a total of $345 million
remaining to be spent.
9
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 2001 Annual Report
A significant portion of costs related to the acid rain and ozone
non-attainment provisions of the Clean Air Act is expected to be recovered
through existing ratemaking provisions. However, there can be no assurance that
all Clean Air Act costs will be recovered.
In July 1997, the Environmental Protection Agency (EPA) revised the
national ambient air quality standards for ozone and particulate matter. This
revision made the standards significantly more stringent. In the subsequent
litigation of these standards, the U.S. Supreme Court found the EPA's
implementation program for the new ozone standard unlawful and remanded it to
the EPA. In addition, the Federal District of Columbia Circuit Court of Appeals
is considering other legal challenges to these standards. If the standards are
eventually upheld, implementation could be required by 2007 to 2010.
In September 1998, the EPA issued regional nitrogen oxide reduction rules
to the states for implementation. The final rule affects 21 states including
Georgia. Compliance is required by May 31, 2004. The EPA proposed rules for
Georgia on February 13, 2002. The EPA's proposal includes a May 1, 2005
implementation date for Georgia. The Company plans to demonstrate compliance
based largely on NOx controls already installed to meet the Atlanta
non-attainment requirements, coupled with the purchase of NOx credits within a
NOx trading market.
In December 2000, having completed its utility study for mercury and other
hazardous air pollutants (HAPS), the EPA issued a determination that an emission
control program for mercury and, perhaps, other HAPS is warranted. The program
is to be developed under the Maximum Achievable Control Technology provisions of
the Clean Air Act, and regulations are scheduled to be finalized by the end of
2004 with implementation to take place around 2007. In January 2001, the EPA
proposed guidance for the determination of Best Available Retrofit Technology
(BART) emission controls under the Regional Haze Regulations. Installation of
BART controls is expected to take place around 2010. Litigation of the Regional
Haze Regulations, including the BART provisions, is ongoing in the Federal
District of Columbia Circuit Court of Appeals. A court decision is expected in
mid-2002.
Implementation of the final state rules for these initiatives could require
substantial further reductions in nitrogen oxide and sulfur dioxide and
reductions in mercury and other HAPS emissions from fossil-fired generating
facilities and other industries in these states. Additional compliance costs and
capital expenditures resulting from the implementation of these rules and
standards cannot be determined until the results of legal challenges are known,
and the states have adopted their final rules.
In October 1997, the EPA issued regulations setting forth requirements for
Compliance Assurance Monitoring (CAM) in state and federal operating permit
programs. These regulations were amended by the EPA in March 2001 in response to
a court order resolving challenges to the rules brought by environmental groups
and industry. Generally, this rule affects the operation and maintenance of
electrostatic precipitators and could involve significant additional ongoing
expense.
The EPA and state environmental regulatory agencies are reviewing and
evaluating various matters including: control strategies to reduce regional
haze; limits on pollutant discharges to impaired waters; cooling water intake
restrictions; and hazardous waste disposal requirements. The impact of any new
standards will depend on the development and implementation of applicable
regulations.
Environmental Protection Agency Litigation
On November 3, 1999, the EPA brought a civil action in the U.S. District Court
for the Northern District of Georgia. The complaint alleges violations of the
prevention of significant deterioration and new source review provisions of the
Clean Air Act with respect to coal-fired generating facilities at the Company's
Bowen and Scherer plants. 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 EPA concurrently issued a notice
of violation to the Company relating to these two plants. In early 2000, the EPA
filed a motion to amend its complaint to add the violations alleged in its
notice of violation. The complaint and the notice of violation are similar to
those brought against and issued to several other electric utilities. The
complaint and the notice of violation allege that the Company failed to secure
necessary permits or install additional pollution control equipment when
performing maintenance and construction at coal burning plants constructed or
under construction prior to 1978. The Company believes that it complied with
applicable laws and the EPA's regulations and interpretations in effect at the
10
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 2001 Annual Report
time the work in question took place. The Clean Air Act authorizes civil
penalties of up to $27,500 per day per violation at each generating unit. Prior
to January 30, 1997, the penalty was $25,000 per day.
The case against the Company has been stayed since the spring of 2001
pending a ruling by the federal Court of Appeals for the Eleventh Circuit in the
appeal of a very similar Clean Air Act / New Source Review enforcement action
brought by EPA against the Tennessee Valley Authority (TVA). The TVA case
involves many of the same legal issues raised by the actions against the
Company. Because the outcome of the TVA case could have a significant adverse
impact on Georgia Power, the Company is a party to that case as well. The
federal court in Georgia is currently considering a motion by the EPA to reopen
the case. The Company has opposed that motion. An adverse outcome of 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.
Other Environmental Issues
The Company must comply with other environmental laws and regulations that cover
the handling and disposal of hazardous waste. Under these various laws and
regulations, the Company could incur costs to clean up properties currently or
previously owned. The Company conducts studies to determine the extent of any
required clean-up and has recognized in the financial statements costs to clean
up known sites. These costs for the Company amounted to $0.6 million in 2001 and
$4 million in both 2000 and 1999. Additional sites may require environmental
remediation for which the Company may be liable for all or a portion of required
clean-up costs. See Note 3 to the financial statements under "Other
Environmental Contingencies" for information regarding the Company's potentially
responsible party status at sites in Georgia.
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; and the Endangered Species Act. Changes to these
laws could affect many areas of the Company's operations. The full impact of any
such changes cannot be determined at this time.
Compliance with possible additional legislation related to global climate
change, electromagnetic fields, and other environmental and health concerns
could significantly affect the Company. The impact of new legislation -- if any
- -- will depend on the subsequent development and implementation of applicable
regulations. In addition, the potential exists for liability as the result of
lawsuits alleging damages caused by electromagnetic fields.
CAUTIONARY STATEMENT REGARDING
FORWARD-LOOKING INFORMATION
The Company's 2001 Annual Report includes forward-looking statements in addition
to historical information. In some cases, forward-looking statements can be
identified by terminology such as "may," "will," "could," "should," "expects,"
"plans," "anticipates," "believes," "estimates," "predicts," "projects,"
"potential" or "continue" or the negative of these terms or other comparable
terminology. The Company cautions that there are various important factors that
could cause actual results to differ materially from those indicated in 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 and other laws and regulations to which the Company is subject,
as well as changes in application of existing laws and regulations; current and
future litigation, including the pending EPA civil action and the race
discrimination litigation against the Company; the effect, extent, and timing of
the entry of additional competition in the markets in which the Company
operates; the impact of fluctuations in commodity prices, interest rates, and
customer demand; state and federal rate regulations; political, legal, and
economic conditions and developments in the United States; the effects of, and
changes in economic conditions in the areas in which the Company operates;
internal restructuring or other restructuring options that may be pursued by the
Company; potential business strategies, including acquisitions or dispositions
of assets or businesses, which cannot be assured to be completed or
11
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 2001 Annual Report
beneficial; the direct or indirect effects on the Company's business resulting
from the terrorist incidents on September 11, 2001, or any similar such
incidents or responses to such incidents; financial market conditions and the
results of financing efforts; the ability of the Company to obtain additional
generating capacity at competitive prices; weather and other natural phenomena;
and other factors discussed elsewhere herein and in other reports (including
Form 10-K) filed from time to time by the Company with the Securities and
Exchange Commission.
12
STATEMENTS OF INCOME
For the Years Ended December 31, 2001, 2000, and 1999
Georgia Power Company 2001 Annual Report
- -------------------------------------------------------------------------------------------------------------
2001 2000 1999
- -------------------------------------------------------------------------------------------------------------
(in thousands)
Operating Revenues:
Retail sales $4,349,312 $4,317,338 $4,050,088
Sales for resale --
Non-affiliates 366,085 297,643 210,104
Affiliates 99,411 96,150 76,426
Other revenues 150,986 159,487 120,057
- -------------------------------------------------------------------------------------------------------------
Total operating revenues 4,965,794 4,870,618 4,456,675
- -------------------------------------------------------------------------------------------------------------
Operating Expenses:
Operation --
Fuel 939,092 1,017,878 919,876
Purchased power --
Non-affiliates 442,196 356,189 214,573
Affiliates 329,232 239,815 174,989
Other 810,043 795,458 784,359
Maintenance 430,413 404,189 411,983
Depreciation and amortization 600,631 619,094 552,966
Taxes other than income taxes 202,483 204,527 202,853
- -------------------------------------------------------------------------------------------------------------
Total operating expenses 3,754,090 3,637,150 3,261,599
- -------------------------------------------------------------------------------------------------------------
Operating Income 1,211,704 1,233,468 1,195,076
Other Income (Expense):
Interest income 4,264 2,629 5,583
Equity in earnings of unconsolidated subsidiaries 4,178 3,051 2,721
Other, net (2,816) (50,495) (47,986)
- -------------------------------------------------------------------------------------------------------------
Earnings Before Interest and Income Taxes 1,217,330 1,188,653 1,155,394
- -------------------------------------------------------------------------------------------------------------
Interest Charges and Other:
Interest expense, net 183,879 208,868 194,869
Distributions on preferred securities of subsidiaries 59,104 59,104 65,774
- -------------------------------------------------------------------------------------------------------------
Total interest charges and other, net 242,983 267,972 260,643
- -------------------------------------------------------------------------------------------------------------
Earnings Before Income Taxes 974,347 920,681 894,751
Income taxes 363,599 360,587 351,639
- -------------------------------------------------------------------------------------------------------------
Net Income Before Cumulative Effect of
Accounting Change 610,748 560,094 543,112
Cumulative effect of accounting change --
less income taxes of $162 thousand 257 - -
- -------------------------------------------------------------------------------------------------------------
Net Income 611,005 560,094 543,112
Dividends on Preferred Stock 670 674 1,729
- -------------------------------------------------------------------------------------------------------------
Net Income After Dividends on Preferred Stock $ 610,335 $ 559,420 $ 541,383
=============================================================================================================
The accompanying notes are an integral part of these statements.
13
STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2001, 2000, and 1999
Georgia Power Company 2001 Annual Report
- -------------------------------------------------------------------------------------------------------------------------------
2001 2000 1999
- -------------------------------------------------------------------------------------------------------------------------------
(in thousands)
Operating Activities:
Net income $ 611,005 $ 560,094 $ 543,112
Adjustments to reconcile net income to net
cash provided from operating activities --
Depreciation and amortization 697,143 712,960 663,878
Deferred income taxes and investment tax credits, net (48,329) (28,961) (34,930)
Other, net (92,403) (51,501) (42,179)
Changes in certain current assets and liabilities --
Receivables, net 60,914 (108,621) 21,665
Fossil fuel stock (103,296) 26,835 (22,165)
Materials and supplies (15,628) (9,715) (10,417)
Accounts payables (15,406) 64,412 13,095
Energy cost recovery, retail (29,839) (95,235) (26,862)
Other (2,999) (9,092) 90,788
- -------------------------------------------------------------------------------------------------------------------------------
Net cash provided from operating activities 1,061,162 1,061,176 1,195,985
- -------------------------------------------------------------------------------------------------------------------------------
Investing Activities:
Gross property additions (1,389,751) (1,078,163) (790,464)
Sales of property 534,760 - -
Other (4,774) (5,450) (27,454)
- -------------------------------------------------------------------------------------------------------------------------------
Net cash used for investing activities (859,765) (1,083,613) (817,918)
- -------------------------------------------------------------------------------------------------------------------------------
Financing Activities:
Increase in notes payable, net 43,698 67,598 295,389
Proceeds --
Senior notes 600,000 300,000 100,000
Pollution control bonds 404,535 78,725 238,000
Preferred securities - - 200,000
Capital contributions from parent company 225,060 301,514 155,777
Retirements --
First mortgage bonds (390,140) (100,000) (404,000)
Pollution control bonds (385,035) (78,725) (235,000)
Preferred securities - - (100,000)
Preferred stock - (383) (36,231)
Capital distributions to parent company (160,000) - -
Payment of preferred stock dividends (578) (751) (984)
Payment of common stock dividends (527,300) (549,600) (543,000)
Other (17,747) (1,231) (29,630)
- -----------------------------------------------------------------------------------------------------------------------------
Net cash provided from (used for) financing activities (207,507) 17,147 (359,679)
- -----------------------------------------------------------------------------------------------------------------------------
Net Change in Cash and Cash Equivalents (6,110) (5,290) 18,388
Cash and Cash Equivalents at Beginning of Year 29,370 34,660 16,272
- -----------------------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of Year $23,260 $29,370 $34,660
- -----------------------------------------------------------------------------------------------------------------------------
Supplemental Cash Flow Information:
Cash paid during the year for --
Interest (net of amount capitalized) $ 234,456 $ 265,373 $ 247,050
Income taxes (net of refunds) 381,995 392,310 394,457
- -----------------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these statements.
14
BALANCE SHEETS
At December 31, 2001 and 2000
Georgia Power Company 2001 Annual Report
- ------------------------------------------------------------------------------------------------------------------
Assets 2001 2000
- ------------------------------------------------------------------------------------------------------------------
(in thousands)
Current Assets:
Cash and cash equivalents $ 23,260 $ 29,370
Receivables --
Customer accounts receivable 376,322 465,249
Underrecovered retail fuel clause revenue 161,462 131,623
Other accounts and notes receivable 129,073 156,143
Affiliated companies 87,786 13,312
Accumulated provision for uncollectible accounts (8,895) (5,100)
Fossil fuel stock, at average cost 202,759 99,463
Materials and supplies, at average cost 279,237 263,609
Other 125,246 97,515
- ------------------------------------------------------------------------------------------------------------------
Total current assets 1,376,250 1,251,184
- ------------------------------------------------------------------------------------------------------------------
Property, Plant, and Equipment:
In service 16,886,399 16,469,706
Less accumulated provision for depreciation 7,243,209 6,914,512
- ------------------------------------------------------------------------------------------------------------------
9,643,190 9,555,194
Nuclear fuel, at amortized cost 112,771 120,570
Construction work in progress (Note 4) 883,285 652,264
- ------------------------------------------------------------------------------------------------------------------
Total property, plant, and equipment 10,639,246 10,328,028
- ------------------------------------------------------------------------------------------------------------------
Other Property and Investments:
Equity investments in unconsolidated subsidiaries (Note 4) 35,209 29,569
Nuclear decommissioning trusts 364,180 375,666
Other 29,618 29,745
- ------------------------------------------------------------------------------------------------------------------
Total other property and investments 429,007 434,980
- ------------------------------------------------------------------------------------------------------------------
Deferred Charges and Other Assets:
Deferred charges related to income taxes (Note 8) 543,584 565,982
Prepaid pension costs 228,259 147,271
Debt expense, being amortized 58,165 53,748
Premium on reacquired debt, being amortized 173,724 173,610
Other 117,706 120,964
- ------------------------------------------------------------------------------------------------------------------
Total deferred charges and other assets 1,121,438 1,061,575
- ------------------------------------------------------------------------------------------------------------------
Total Assets $13,565,941 $13,075,767
==================================================================================================================
The accompanying notes are an integral part of these balance sheets.
15
BALANCE SHEETS
At December 31, 2001 and 2000
Georgia Power Company 2001 Annual Report
- --------------------------------------------------------------------------------------------------------------------
Liabilities and Stockholder's Equity 2001 2000
- --------------------------------------------------------------------------------------------------------------------
(in thousands)
Current Liabilities:
Securities due within one year (Note 9) $ 311,620 $ 1,808
Notes payable 747,537 703,839
Accounts payable --
Affiliated 109,591 117,168
Other 409,253 397,550
Customer deposits 83,172 78,540
Taxes accrued --
Income taxes 35,247 5,151
Other 125,807 137,511
Interest accrued 46,942 47,244
Vacation pay accrued 41,830 38,865
Other 112,686 137,565
- --------------------------------------------------------------------------------------------------------------------
Total current liabilities 2,023,685 1,665,241
- --------------------------------------------------------------------------------------------------------------------
Long-term debt (See accompanying statements) 2,961,726 3,041,939
- --------------------------------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes (Note 8) 2,163,959 2,182,783
Deferred credits related to income taxes (Note 8) 229,216 247,067
Accumulated deferred investment tax credits (Note 8) 337,482 352,282
Employee benefits provisions 207,795 191,587
Other 440,774 341,505
- --------------------------------------------------------------------------------------------------------------------
Total deferred credits and other liabilities 3,379,226 3,315,224
- --------------------------------------------------------------------------------------------------------------------
Company obligated mandatorily redeemable preferred
securities of subsidiary trusts holding company junior
subordinated notes (See accompanying statements) 789,250 789,250
- --------------------------------------------------------------------------------------------------------------------
Cumulative preferred stock (See accompanying statements) 14,569 14,569
- --------------------------------------------------------------------------------------------------------------------
Common stockholder's equity (See accompanying statements) 4,397,485 4,249,544
- --------------------------------------------------------------------------------------------------------------------
Total Liabilities and Stockholder's Equity $13,565,941 $13,075,767
====================================================================================================================
The accompanying notes are an integral part of these balance sheets.
16
STATEMENTS OF CAPITALIZATION
At December 31, 2001 and 2000
Georgia Power Company 2001 Annual Report
- -----------------------------------------------------------------------------------------------------------------------------------
2001 2000 2001 2000
- -----------------------------------------------------------------------------------------------------------------------------------
(in thousands) (percent of total)
Long-Term Debt:
First mortgage bonds
Maturity Interest Rates
- -------- -------------
April 1, 2003 6.625% $ - $ 200,000
August 1, 2003 6.35% - 75,000
2005 6.07% 1,860 10,000
2008 6.875% - 50,000
2025 7.70% - 57,000
- --------------------------------------------------------------------------------------------------------------
Total first mortgage bonds 1,860 392,000
- --------------------------------------------------------------------------------------------------------------
Senior notes -- (Note 9)
Variable rate (1.98125% at 1/1/02) due February 22, 2002 300,000 300,000
5.75% due January 31, 2003 200,000 -
5.25% due May 8, 2003 150,000 -
5.50% due December 1, 2005 150,000 150,000
6.20% due February 1, 2006 150,000 -
6.70% due March 1, 2011 100,000 -
6.60% due December 31, 2038 200,000 200,000
6.625% due March 31, 2039 100,000 100,000
6.875% due December 31, 2047 145,000 145,000
- --------------------------------------------------------------------------------------------------------------
Total senior notes payable 1,495,000 895,000
- --------------------------------------------------------------------------------------------------------------
Other long-term debt -- (Note 9)
Pollution control revenue bonds --
Maturity Interest Rates
------- -------------
2005 5.00% - 57,000
2011 Variable (1.90% to 1.95% at 1/1/02) 10,450 10,450
2012-2016 4.20% to 5.00% 164,590 -
2018-2021 6.00% to 6.25% 7,800 23,225
2018 Variable (2.00% at 1/1/02) 19,500 -
2023-2025 4.90% to 6.75% 28,065 298,535
2022-2026 Variable (1.75% to 1.95% at 1/1/02) 669,480 683,555
2029 Variable (1.90% to 1.95% at 1/1/02) 144,700 144,700
2030-2031 4.53% to 5.25% 137,570 78,725
2032-2034 Variable (1.75% to 1.95% at 1/1/02) 140,000 140,000
2032-2034 4.45% to 5.45% 371,535 238,000
- --------------------------------------------------------------------------------------------------------------
Total other long-term debt 1,693,690 1,674,190
- --------------------------------------------------------------------------------------------------------------
Capital lease obligations (Note 9) 83,371 85,179
- --------------------------------------------------------------------------------------------------------------
Unamortized debt discount, net (575) (2,622)
- --------------------------------------------------------------------------------------------------------------
Total long-term debt (annual interest)
requirement -- $139.5 million) 3,273,346 3,043,747
Less amount due within one year (Note () 311,620 1,808
- -----------------------------------------------------------------------------------------------------------------------------------
Total long-term debt excluding amount due within one year $ 2,961,726 $ 3,041,939 36.3 % 37.6 %
- -----------------------------------------------------------------------------------------------------------------------------------
17
STATEMENTS OF CAPITALIZATION (continued)
At December 31, 2001 and 2000
Georgia Power Company 2001 Annual Report
- -----------------------------------------------------------------------------------------------------------------------------------
2001 2000 2001 2000
- -----------------------------------------------------------------------------------------------------------------------------------
(in thousands) (percent of total)
Company Obligated Mandatorily
Redeemable Preferred Securities (Note 9):
$25 liquidation value -- 6.85% $ 200,000 $ 200,000
$25 liquidation value -- 7.60% 175,000 175,000
$25 liquidation value -- 7.75% 189,250 189,250
$25 liquidation value -- 7.75% 225,000 225,000
- -----------------------------------------------------------------------------------------------------------------------------------
Total (annual distribution requirement -- $59.1 million) 789,250 789,250 9.6 9.7
- -----------------------------------------------------------------------------------------------------------------------------------
Cumulative Preferred Stock, without par value:
Authorized -- 55,000,000 shares
Outstanding -- 145,689 shares at December 31, 2001
Outstanding -- 145,689 shares at December 31, 2000
$100 stated value --
4.60% 14,569 14,569
- -----------------------------------------------------------------------------------------------------------------------------------
Total cumulative preferred stock (annual dividend
requirement -- $0.7 million) 14,569 14,569 0.2 0.2
- -----------------------------------------------------------------------------------------------------------------------------------
Common Stockholder's Equity:
Common stock, without par value --
Authorized -- 15,000,000 shares
Outstanding -- 7,761,500 shares 344,250 344,250
Paid-in capital 2,182,557 2,117,497
Premium on preferred stock 40 40
Other comprehensive income (153) -
Retained earnings (Note 9) 1,870,791 1,787,757
- -----------------------------------------------------------------------------------------------------------------------------------
Total common stockholder's equity (See accompanying statements) 4,397,485 4,249,544 53.9 52.5
- -----------------------------------------------------------------------------------------------------------------------------------
Total Capitalization $ 8,163,030 $ 8,095,302 100.0 % 100.0 %
- -----------------------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these statements.
18
STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
For the Years Ended December 31, 2001, 2000, and 1999
Georgia Power Company 2001 Annual Report
- -------------------------------------------------------------------------------------------------------------------------
Premium on Other
Common Paid-In Preferred Retained Comprehensive
Stock Capital Stock Earnings Income (Loss) Total
- ------------------------------------------------------------------------------------------------------------------------------
Balance at January 1, 1999 $344,250 $1,660,206 $158 $1,779,558 $ - $3,784,172
Net income after dividends on preferred stock - - - 541,383 - 541,383
Capital contributions from parent company - 155,777 - - - 155,777
Cash dividends on common stock - - - (543,000) - (543,000)
Preferred stock transactions, net - - (118) (4) - (122)
- -------------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 1999 344,250 1,815,983 40 1,777,937 - 3,938,210
Net income after dividends on preferred stock - - - 559,420 - 559,420
Capital contributions from parent company - 301,514 - - - 301,514
Cash dividends on common stock - - - (549,600) - (549,600)
- -------------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 2000 344,250 2,117,497 40 1,787,757 - 4,249,544
Net income after dividends on preferred stock - - - 610,335 - 610,335
Capital contributions from parent company - 225,060 - - - 225,060
Capital distributions to parent company (160,000) (160,000)
Other comprehensive income - - - - (153) (153)
Cash dividends on common stock - - - (527,300) - (527,300)
Preferred stock transactions, net - - - (1) - (1)
- -------------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 2001 $344,250 $2,182,557 $40 $1,870,791 ($153) $4,397,485
===============================================================================================================================
STATEMENTS OF COMPREHENSIVE INCOME
For the Years Ended December 31, 2001, 2000, and 1999
Georgia Power Company 2001 Annual Report
- ---------------------------------------------------------------------------------------------------------------------------
2001 2000 1999
- ---------------------------------------------------------------------------------------------------------------------------
(in thousands)
Net income after dividends on preferred stock $ 610,335 $ 559,420 $ 541,383
Other comprehensive income:
Cumulative effect of accounting change, net of tax 286 - -
Current period changes in fair value, net of tax (439) - -
- ---------------------------------------------------------------------------------------------------------------------------
Comprehensive Income $ 610,182 $ 559,420 $ 541,383
===========================================================================================================================
The accompanying notes are an integral part of these statements.
19
NOTES TO FINANCIAL STATEMENTS
Georgia Power Company 2001 Annual Report
1. SUMMARY OF SIGNIFICANT ACCOUNTING
POLICIES
General
The Company is a wholly owned subsidiary of Southern Company, which is the
parent company of five operating companies, a system service company (SCS),
Southern Communications Services (Southern LINC), Southern Nuclear Operating
Company (Southern Nuclear), Southern Power Company (Southern Power), and other
direct and indirect subsidiaries. The operating companies --Alabama Power
Company, Georgia Power Company, Gulf Power Company, Mississippi Power Company,
and Savannah Electric and Power Company-- provide electric service in four
southeastern states. Contracts among the operating companies -- related to
jointly owned generating facilities, interconnecting transmission lines, and the
exchange of electric power -- are regulated by the Federal Energy Regulatory
Commission (FERC) and/or the Securities and Exchange Commission. SCS provides,
at cost, specialized services to Southern Company and subsidiary companies.
Southern LINC provides digital wireless communications services to the operating
companies and also markets these services to the public within the Southeast.
Southern Nuclear provides services to Southern Company's nuclear power plants.
Southern Power was established in 2001 to construct, own, and manage Southern
Company's competitive generation assets and sell electricity at market-based
rates in the wholesale market.
Southern Company is registered as a holding company under the Public
Utility Holding Company Act of 1935 (PUHCA). Both Southern Company and its
subsidiaries are subject to the regulatory provisions of the PUHCA. The Company
is also subject to regulation by the FERC and the Georgia Public Service
Commission (GPSC). The Company follows accounting principles generally accepted
in the United States and complies with the accounting policies and practices
prescribed by the respective 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 these estimates.
Certain prior years' data presented in the financial statements have been
reclassified to conform with current year presentation.
Affiliate Transactions
The Company has an agreement with SCS under which the following services are
rendered to the Company at cost: general and design engineering, purchasing,
accounting and statistical, finance and treasury, tax, information resources,
marketing, auditing, insurance and pension, human resources, systems and
procedures, and other services with respect to business and operations and power
pool operations. Costs for these services amounted to $285 million, $269
million, and $253 million during 2001, 2000, and 1999, respectively.
The Company has an agreement with Southern Nuclear under which the
following nuclear-related services are rendered to the Company at cost: general
executive and advisory services; general operations, management and technical
services; administrative services including procurement, accounting and
statistical, employee relations, and systems and procedures services; strategic
planning and budgeting services; and other services with respect to business and
operations. Costs for these services amounted to $281 million in both 2001 and
2000 and $270 million in 1999.
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 expected to be credited to
customers through the ratemaking process. See Note 3 under "Retail Rate Orders"
for additional information regarding the disposition of the regulatory liability
for the accelerated cost recovery recorded under the retail rate order that
ended December 31, 2001. Regulatory assets and (liabilities) reflected in the
Company's Balance Sheets at December 31 relate to the following:
20
NOTES (continued)
Georgia Power Company 2001 Annual Report
2001 2000
----------------------
(in millions)
Deferred income taxes $ 544 $ 566
Deferred income tax credits (229) (247)
Premium on reacquired debt 174 174
Corporate building lease 54 55
Vacation pay 52 49
Postretirement benefits 28 30
Department of Energy assessments 18 21
Deferred nuclear outage costs 24 28
Accelerated cost recovery and
interest (336) (230)
Other, net 16 23
--------------------------------------------------------------
Total $ 345 $ 469
===============================================================
In the event that a portion of the Company's operations is no longer
subject to the provisions of 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 value.
Revenues and Fuel Costs
The Company currently operates as a vertically integrated utility providing
electricity to retail customers within its traditional service area located
within the state of Georgia, and to wholesale customers in the Southeast.
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 1 percent of revenues.
Revenues are recognized as services are rendered. Unbilled revenues are
accrued at the end of each fiscal period. Fuel costs are expensed as the fuel is
used. The Company's fuel cost recovery mechanism includes provisions to adjust
billings for fluctuations in fuel costs, the energy component of purchased power
costs, and certain other costs. Revenues are adjusted for differences between
recoverable fuel costs and amounts actually recovered in current rates.
Fuel expense 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 $75
million in each of 2001 and 2000 and $74 million in 1999. The Company has
contracts with the U.S. Department of Energy (DOE) that provide for the
permanent disposal of used nuclear fuel. The DOE failed to begin disposing of
used nuclear fuel in January 1998 as required by the contracts, and the Company
is pursuing legal remedies against the government for breach of contract.
Sufficient pool storage capacity is available at Plant Vogtle to maintain
full-core discharge capability for both units until the year 2014. To maintain
pool discharge capability at Plant Hatch, effective June 2000, an on-site dry
storage facility for Plant Hatch became operational. Sufficient dry storage
capacity is believed to be available to continue dry storage operations at Plant
Hatch through the life of the plant. Procurement of on-site dry storage capacity
at Plant Vogtle will commence in sufficient time to maintain pool full-core
discharge capability.
Also, the Energy Policy Act of 1992 required the establishment of a Uranium
Enrichment Decontamination and Decommissioning Fund, which is to be funded in
part by a special assessment on utilities with nuclear plants. The assessment
will be 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 -- based on
its ownership interests -- estimates its remaining liability under this law at
December 31, 2001 to be approximately $16 million. This obligation is recorded
in the accompanying Balance Sheets.
Depreciation and Nuclear Decommissioning
Depreciation of the original cost of depreciable utility plant in service is
provided primarily by using composite straight-line rates, which approximated
3.3 percent in 2001, 2000, and 1999. 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. Depreciation
expense includes an amount for the expected costs of decommissioning nuclear
facilities and removal of other facilities.
Nuclear Regulatory Commission (NRC) regulations require all licensees
operating commercial power reactors to establish a plan for providing, with
21
NOTES (continued)
Georgia Power Company 2001 Annual Report
reasonable assurance, funds for decommissioning. The Company has established
external trust funds to comply with the NRC's regulations. Earnings on the trust
funds are considered in determining decommissioning expense. The NRC's minimum
external funding requirements are based on a generic estimate of the cost to
decommission 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.
The Company periodically conducts site-specific studies to estimate the
actual cost of decommissioning its nuclear generating facilities. Site study
cost is the estimate to decommission the facility as of the site study year, and
ultimate cost is the estimate to decommission the facility as of its retirement
date. The estimated site study costs based on the most current study and
ultimate costs assuming an inflation rate of 4.7 percent for the Company's
ownership interests are as follows:
Plant Plant
Hatch Vogtle
--------------------
Site study basis (year) 2000 2000
Decommissioning periods:
Beginning year 2014 2027
Completion year 2042 2045
- -------------------------------------------------------------
(in millions)
Site study costs:
Radiated structures $486 $420
Non-radiated structures 37 48
- -------------------------------------------------------------
Total $523 $468
=============================================================
(in millions)
Ultimate costs:
Radiated structures $1,004 $1,468
Non-radiated structures 79 166
- -------------------------------------------------------------
Total $1,083 $1,634
=============================================================
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 the NRC requirements, changes in the assumptions
used in making the estimates, changes in regulatory requirements, changes in
technology, and changes in costs of labor, materials, and equipment.
Annual provisions for nuclear decommissioning expense are based on an
annuity method as approved by the GPSC. The amounts expensed in 2001 and fund
balances as of December 31, 2001 were:
Plant Plant
Hatch Vogtle
- ----------------------------------------------------------------
(in millions)
Amount expensed in 2001 $20 $9
================================================================
(in millions)
Accumulated provisions:
External trust funds, at fair value $229 $135
Internal reserves 20 12
- ----------------------------------------------------------------
Total $249 $147
================================================================
Effective January 1, 2002, the GPSC decreased the annual provision for
decommissioning expenses to $8 million. This amount is based on the NRC generic
estimate to decommission the radioactive portion of the facilities as of 2000
of $383 million and $282 million for Plants Hatch and Vogtle, respectively. The
ultimate costs associated with the 2000 NRC minimum funding requirements are
$823 million and $1.03 billion for Plants Hatch and Vogtle, respectively.
Significant assumptions include an estimated inflation rate of 4.7 percent and
an estimated trust earnings rate of 6.5 percent. The Company expects the GPSC
to periodically review and adjust, if necessary, the amounts collected in rates
for the anticipated cost of decommissioning.
In January 2002, the NRC granted the Company a 20-year extension of the
licenses for both units at Plant Hatch which permits the operation of units 1
and 2 until 2034 and 2038, respectively. The decommissioning costs disclosed
above do not reflect this extension.
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 lives of the related property.
Allowance for Funds Used During Construction
(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
22
NOTES (continued)
Georgia Power Company 2001 Annual Report
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. For the years 2001, 2000, and 1999, the average AFUDC
rates were 6.33 percent, 6.74 percent, and 5.61 percent, respectively. AFUDC,
net of taxes, as a percentage of net income after dividends on preferred stock,
was less than 3.0 percent for 2001, 2000, and 1999.
Property, Plant, and Equipment
Property, plant, and equipment is stated at original cost, less regulatory
disallowances and impairments. Original cost includes: materials; labor;
payroll-related costs such as taxes, pensions, and other benefits; and the cost
of funds used during construction. The cost of maintenance, repairs, and
replacement of minor items of property is charged to maintenance expense. The
cost of replacements of property (exclusive of minor items of property) is
capitalized.
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.
Comprehensive Income
Comprehensive income -- consisting of net income and changes in the fair value
of qualifying cash flow hedges, net of income taxes -- is presented in the
financial statements. 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.
Financial Instruments
Effective January 2001, the Company adopted FASB Statement No. 133, Accounting
for Derivative Instruments and Hedging Activities, as amended. The impact on net
income was immaterial.
The Company uses derivative financial instruments to hedge exposures to
fluctuations in interest rates, foreign currency exchange rates, and certain
commodity prices. Gains and losses on qualifying hedges are deferred and
recognized either in income or as an adjustment to the carrying amount of the
hedged item when the transaction occurs.
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.
The Company and its affiliates, through SCS acting as their agent, enter into
commodity related forward and option contracts to limit exposure to changing
prices on certain fuel purchases and electricity purchases and sales.
Substantially all of the Company's bulk energy purchases and sales contracts
meet the definition of a derivative under Statement No. 133. In many cases,
these fuel and electricity contracts qualify for normal purchase and sale
exceptions under Statement No. 133 and are accounted for under the accrual
method. Other contracts qualify as cash flow hedges of anticipated transactions,
resulting in the deferral of related gains and losses, and are recorded in other
comprehensive income until the hedged transactions occur. Any ineffectiveness is
recognized currently in net income. Contracts that do not qualify for the normal
purchase and sale exception and that do not meet the hedge requirements are
marked to market through current period income.
The Company's financial instruments for which the carrying amounts did not
approximate fair value at December 31 were as follows:
Carrying Fair
Amount Value
------------------------
Long-term debt: (in millions)
At December 31, 2001 $3,190 $3,190
At December 31, 2000 $2,959 $2,912
Preferred securities:
At December 31, 2001 $789 $782
At December 31, 2000 $789 $761
- --------------------------------------------------- ----------
The fair values for securities were based on either closing market prices
or closing prices of comparable instruments.
Materials and Supplies
Generally, materials and supplies include the cost of transmission,
distribution, and generating plant materials. Materials are charged to inventory
23
NOTES (continued)
Georgia Power Company 2001 Annual Report
when purchased and then expensed or capitalized to plant, as appropriate, when
installed.
2. RETIREMENT BENEFITS
The Company has defined benefit, trusteed pension plans that cover substantially
all employees. The Company provides certain medical care and life insurance
benefits for retired employees. Substantially all these employees may become
eligible for such benefits when they retire. The Company funds postretirement
trusts to the extent required by the GPSC and the FERC. In late 2000, the
Company adopted several pension and postretirement benefits plan changes that
had the effect of increasing benefits to both current and future retirees. The
measurement date for plan assets and obligations is September 30 of each year.
The weighted average rates assumed in the actuarial calculations for both
the pension and postretirement benefit plans were:
2001 2000
- -----------------------------------------------------------------
Discount 7.50% 7.50%
Annual salary increase 5.00 5.00
Expected long-term return on plan
assets 8.50 8.50
- -----------------------------------------------------------------
Pension Plan
Changes during the year in the projected benefit obligations and in the fair
value of plan assets were as follows:
Projected
Benefit Obligations
--------------------------
2001 2000
- ---------------------------------------------------------------
(in millions)
Balance at beginning of year $1,322 $1,275
Service cost 35 32
Interest cost 101 94
Benefits paid (74) (67)
Actuarial gain and
employee transfers 64 (12)
- ---------------------------------------------------------------
Balance at end of year $1,448 $1,322
===============================================================
Plan Assets
---------------------------
2001 2000
- ----------------------------------------------------------------
(in millions)
Balance at beginning of year $2,464 $2,107
Actual return on plan assets (356) 385
Benefits paid (62) (58)
Employee transfers (2) 30
- ----------------------------------------------------------------
Balance at end of year $2,044 $2,464
================================================================
The accrued pension costs recognized in the Balance Sheets
were as follows:
2001 2000
- ---------------------------------------------------------------
(in millions)
Funded status $ 596 $ 1,142
Unrecognized transition obligation (22) (26)
Unrecognized prior service cost 98 44
Unrecognized net actuarial gain (444) (1,013)
- ---------------------------------------------------------------
Prepaid asset recognized in the
Balance Sheets $ 228 $ 147
===============================================================
Components of the plan's net periodic cost were as follows:
2001 2000 1999
- ---------------------------------------------------------------
(in millions)
Service cost $ 35 $ 33 $ 33
Interest cost 101 94 86
Expected return on plan assets (168) (152) (137)
Recognized net actuarial gain (31) (26) (17)
Net amortization 3 (1) -
- ---------------------------------------------------------------
Net pension income $ (60) $ (52) $ (35)
===============================================================
Postretirement Benefits
Changes during the year in the accumulated benefit obligations and in the fair
value of plan assets were as follows:
Accumulated
Benefit Obligations
-------------------------
2001 2000
- --------------------------------------------------------------
(in millions)
Balance at beginning of year $495 $438
Service cost 9 7
Interest cost 39 36
Benefits paid (24) (21)
Actuarial gain and
employee transfers 23 35
- --------------------------------------------------------------
Balance at end of year $542 $495
==============================================================
24
NOTES (continued)
Georgia Power Company 2001 Annual Report
Plan Assets
---------------------------
2001 2000
- ----------------------------------------------------------------
(in millions)
Balance at beginning of year $198 $177
Actual return on plan assets (26) 12
Employer contributions 47 30
Benefits paid (24) (21)
- ----------------------------------------------------------------
Balance at end of year $195 $198
================================================================
The accrued postretirement costs recognized in the Balance Sheets were as
follows:
2001 2000
- ---------------------------------------------------------------
(in millions)
Funded status $(347) $(297)
Unrecognized transition obligation 105 113
Unrecognized prior service cost 104 60
Unrecognized (gain)/loss 5 (13)
Fourth quarter contributions 27 27
- ---------------------------------------------------------------
Accrued liability recognized in the
Balance Sheets $(106) $(110)
===============================================================
Components of the plans' net periodic cost were as follows:
2001 2000 1999
- ---------------------------------------------------------------
(in millions)
Service cost $ 9 $ 7 $ 8
Interest cost 39 36 30
Expected return on plan assets (19) (16) (10)
Recognized net actuarial loss - - 1
Net amortization 14 12 9
- ---------------------------------------------------------------
Net postretirement cost $ 43 $ 39 $38
===============================================================
An additional assumption used in measuring the accumulated postretirement
benefit obligations was a weighted average medical care cost trend rate of 9.25
percent for 2001, decreasing gradually to 5.25 percent through the year 2010,
and remaining at that level thereafter. An annual increase or decrease in the
assumed medical care cost trend rate of 1 percent would affect the accumulated
benefit obligation and the service and interest cost components at December 31,
2001 as follows:
1 Percent 1 Percent
Increase Decrease
- ---------------------------------------------------------------
(in millions)
Benefit obligation $54 $46
Service and interest costs 5 4
===============================================================
Employee Savings Plan
The Company sponsors a 401(k) defined contribution plan covering substantially
all employees. The Company provides a 75 percent matching contribution up to 6
percent of an employee's base salary. Total matching contributions made to the
plan for the years 2001, 2000, and 1999 were $16 million, $15 million, and $15
million, respectively.
3. CONTINGENCIES AND REGULATORY MATTERS
General
The Company is subject to certain claims and legal actions arising in the
ordinary course of business. In the opinion of management, after consultation
with legal counsel, the ultimate disposition of these matters is not expected to
have a material adverse effect on the Company's financial condition.
Retail Rate Orders
On December 20, 2001, the GPSC approved a new three-year retail rate order for
the Company ending December 31, 2004. Under the terms of the order, earnings
will be evaluated against a retail return on common equity range of 10 percent
to 12.95 percent. Two-thirds of any earnings above the 12.95 percent return will
be applied to rate refunds, with the remaining one-third retained by the
Company. Retail rates were decreased by $118 million effective January 1, 2002.
Under a previous three-year order ending December 2001, the Company's
earnings were evaluated against a retail return on common equity range of 10
percent to 12.5 percent. The order further provided for $85 million in each
year, plus up to $50 million of any earnings above the 12.5 percent return
during the second and third years, to be applied to accelerated amortization or
depreciation of assets. Two-thirds of any additional earnings above the 12.5
percent return were applied to rate refunds, with the remaining one-third
retained by the Company. Pursuant to the order, the Company recorded $336
million of accelerated amortization and interest thereon which has been credited
to a regulatory liability account as mandated by the GPSC.
Under the new rate order, the accelerated amortization and the interest will
be amortized equally over three years as a credit to expense beginning in 2002.
Effective January 1, 2002, the Company discontinued recording accelerated
25
NOTES (continued)
Georgia Power Company 2001 Annual Report
depreciation and amortization. The Company will not file for a general base rate
increase unless its projected retail return on common equity falls below 10
percent. Georgia Power is required to file a general rate case on July 1, 2004,
in response to which the GPSC would be expected to determine whether the rate
order should be continued, modified, or discontinued.
In 2000 and 1999, the Company recorded $44 million and $79 million,
respectively, of revenue subject to refund for estimated earnings above 12.5
percent retail return on common equity. Refunds applicable to 2000 and 1999 were
made to customers in 2001 and 2000, respectively.
Environmental Protection Agency (EPA) Litigation
On November 3, 1999, the EPA brought a civil action in the U.S. District Court
for the Northern District of Georgia. The complaint alleges violations of the
prevention of significant deterioration and new source review provisions of the
Clean Air Act with respect to coal-fired generating facilities at the Company's
Bowen and Scherer plants. The civil action requests penalties and injunctive
relief, including an order requiring the installation of the best available
control technology at the affected units beginning at the point of the alleged
violations. The Clean Air Act authorizes civil penalties of up to $27,500 per
day, per violation at each generating unit. Prior to January 30, 1997, the
penalty was $25,000 per day.
The EPA concurrently issued a notice of violation to the Company relating
to these two plants. In early 2000, the EPA filed a motion to amend its
complaint to add the violations alleged in its notice of violation. The
complaint and the notice of violation are similar to those brought against and
issued to several other electric utilities. The complaint and the notice of
violation allege that the Company failed to secure necessary permits or install
additional pollution control equipment when performing maintenance and
construction at coal burning plants constructed or under construction prior to
1978. The Company believes that it complied with applicable laws and the EPA's
regulations and interpretations in effect at the time the work in question took
place.
The case against the Company has been stayed since the spring of 2001
pending a ruling by the U.S. Court of Appeals for the Eleventh Circuit in the
appeal of a very similar Clean Air Act / New Source Review enforcement action
brought by EPA against the Tennessee Valley Authority (TVA). The TVA case
involves many of the same legal issues raised by the actions against the
Company. Because the outcome of the TVA case could have a significant adverse
impact on Georgia Power, the Company is a party to that case as well. The
federal court in Georgia is currently considering a motion by the EPA to reopen
the Georgia case. The Company has opposed that motion. An adverse outcome of
this matter could require substantial capital expenditures that cannot be
determined at this time and 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.
Other Environmental Contingencies
The Company has been designated as a potentially responsible party at sites
governed by the Georgia Hazardous Site Response Act and/or by the federal
Comprehensive Environmental Response, Compensation and Liability Act. Georgia
Power has recognized $33 million in cumulative expenses through December 31,
2001 for the assessment and anticipated cleanup of sites on the Georgia
Hazardous Sites Inventory. In addition, in 1995 the EPA designated Georgia Power
and four other unrelated entities as potentially responsible parties at a site
in Brunswick, Georgia that is listed on the federal National Priorities List.
Georgia Power has contributed to the removal and remedial investigation and
feasibility study costs for the site. Additional claims for recovery of natural
resource damages at the site are anticipated. As of December 31, 2001, Georgia
Power had recorded approximately $6 million in cumulative expenses associated
with Georgia Power's agreed-upon share of the removal and remedial investigation
and feasibility study costs for the Brunswick site.
The final outcome of these matters cannot now be determined. However, based
on the currently known conditions at these sites and the nature and extent of
Georgia Power's activities relating to these sites, management does not believe
that the Company's cumulative liability at these sites would be material to the
financial statements.
26
NOTES (continued)
Georgia Power Company 2001 Annual Report
Nuclear Performance Standards
The GPSC has adopted a nuclear performance standard for the Company's nuclear
generating units under which the performance of Plants Hatch and Vogtle is
evaluated every three years. The performance standard is based on each unit's
capacity factor as compared to the average of all comparable U.S. nuclear units
operating at a capacity factor of 50 percent or higher during the three-year
period of evaluation. Depending on the performance of the units, the Company
could receive a monetary award or penalty under the performance standards
criteria.
The GPSC has approved performance awards of approximately $11.7 million and
$7.8 million for performance during the 1993-1995 period and the 1996-1998
period, respectively. These awards are collected through the retail fuel cost
recovery provision and recognized in income over 36-month periods that began in
January 1997 and 2000, respectively, as mandated by the GPSC.
Race Discrimination Litigation
On July 28, 2000, a lawsuit alleging race discrimination was filed by three
Georgia Power employees against the Company, Southern Company, and SCS in the
United States District Court for the Northern District of Georgia. The lawsuit
also raised claims on behalf of a purported class. The plaintiffs seek
compensatory and punitive damages in an unspecified amount, as well as
injunctive relief. On August 14, 2000, the lawsuit was amended to add four more
plaintiffs. Also, an additional subsidiary of Southern Company, Southern Company
Energy Solutions, Inc., was named a defendant.
On October 11, 2001, the district court denied plaintiffs' motion for class
certification. The plaintiffs filed a motion to reconsider the order denying
class certification, and the court denied the plaintiffs' motion to reconsider.
On December 28, 2001, the plaintiffs filed a petition in the United States Court
of Appeals for the Eleventh Circuit seeking permission to file an appeal of the
October 11 decision. The defendants filed a brief in opposition of the petition
on January 18, 2002. Discovery of the seven named plaintiffs' individual claims
that remain in the case is ongoing. The final outcome of the case cannot be
determined.
4. COMMITMENTS
Construction Program
Georgia Power had three new generation projects under construction during 2001.
They included two units at Plant Dahlberg, a ten-unit, 800 megawatt combustion
turbine facility; two combined cycle units totaling 1,132 megawatts at Plant
Wansley; and Plant Goat Rock, a two-unit, 1,181 megawatt combined cycle
facility. All three of these projects have been transferred to Southern Power
Company, a new Southern Company affiliate formed in 2001 to construct, own, and
manage wholesale generating assets in the Southeast. The ten Dahlberg units and
two Goat Rock units were transferred in 2001 and the transfer of the two Wansley
units was completed in January 2002. Significant construction of transmission
and distribution facilities and projects to remain in compliance with
environmental requirements will continue. The Company currently estimates
property additions to be approximately $1.0 billion in 2002, $0.8 billion in
2003, and $0.8 billion in 2004.
In connection with the transfer of Plants Dahlberg, Goat Rock, and Wansley,
the Company has assigned $61 million in vendor equipment contracts to Southern
Power. While the Company could be obligated to assume responsibility for these
contracts if Southern Power fails to meet these commitments, Southern Company
has entered into limited keep-well arrangements whereby Southern Company would
contribute funds to Southern Power either through loans or capital
contributions in order to fund performance by Southern Power as equipment
purchaser under certain contingencies. Southern Company has also guaranteed
Southern Power obligations totaling $6.6 milion for the Company's construction
of transmission interconnection facilities to these plants.
The construction program is subject to periodic review and revision, and
actual construction costs may vary from estimates because of numerous factors,
including, but not limited to, changes in business conditions, load growth
estimates, environmental regulations, and regulatory requirements.
Fuel Commitments
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.
27
NOTES (continued)
Georgia Power Company 2001 Annual Report
Total estimated long-term fossil and nuclear fuel commitments at December 31,
2001 were as follows:
Minimum
Year Obligations
- ---- -------------------
(in millions)
2002 $1,234
2003 1,115
2004 617
2005 527
2006 521
2007 and beyond 1,857
- -------------------------------------------------------------
Total $5,871
=============================================================
Additional commitments for coal and for nuclear fuel will be required in
the future to supply the Company's fuel needs.
In addition, SCS acts as agent for the five operating companies and
Southern Power with regard to natural gas purchases. Natural gas purchases (in
dollars) are based on various indices at the actual time of delivery; therefore,
only the volume commitments are firm and disclosed in the following chart. The
committed volumes, as of December 31, 2001 are as follows:
Year Natural Gas
- ---- ------------------
(MMBtu)
2002 18,927,055
2003 30,434,645
2004 30,352,580
2005 23,050,128
2006 20,038,214
2007 and beyond 7,153,129
- ---------------------------------------------------------------
Total 129,955,751
===============================================================
Purchased Power Commitments
The Company and an affiliate, Alabama Power, own equally all of the outstanding
capital stock of Southern Electric Generating Company (SEGCO), which owns
electric generating units with a total rated capacity of 1,020 megawatts, as
well as associated transmission facilities. The capacity of the units has been
sold equally to the Company and Alabama Power under a contract which, in
substance, requires payments sufficient to provide for the operating expenses,
taxes, debt service, and return on investment, 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 expenses included in purchased power from
affiliates in the Statements of Income is as follows:
2001 2000 1999
---------------------------------
(in millions)
Energy $52 $57 $51
Capacity 30 30 29
- --------------------------------------------------------------
Total $82 $87 $80
==============================================================
The Company has commitments regarding a portion of a 5 percent interest in
Plant Vogtle owned by Municipal Electric Authority of Georgia (MEAG) that are in
effect until the latter of the retirement of the plant or the latest stated
maturity date of MEAG's bonds issued to finance such ownership interest. The
payments for capacity are required whether or not any capacity is available. The
energy cost is a function of each unit's variable operating costs. Except as
noted below, the cost of such capacity and energy is included in purchased power
from non-affiliates in the Company's Statements of Income. Capacity payments
totaled $59 million, $58 million, and $57 million in 2001, 2000, and 1999,
respectively. The current projected Plant Vogtle capacity payments are:
Year Capacity Payments
----------------------
(in millions)
2002 $ 58
2003 59
2004 55
2005 55
2006 55
2007 and beyond 483
- ----------------------------------------------------------------
Total $765
================================================================
Portions of the payments noted above relate to costs in excess of Plant
Vogtle's allowed investment for ratemaking purposes. The present value of these
portions was written off in 1987 and 1990.
28
NOTES (continued)
Georgia Power Company 2001 Annual Report
The Company has entered into other various long-term commitments for the
purchase of electricity. Estimated total long-term obligations at December 31,
2001 were as follows:
Year Non-
Affiliated Affiliated
- ---- --------------------------------
(in millions)
2002 $ 66 $ 39
2003 123 41
2004 183 40
2005 198 40
2006 197 40
2007 and beyond 1,138 396
- ------------------------------------------------------------
Total $1,905 $596
============================================================
Operating Leases
The Company has entered into coal rail car rental agreements with various terms
and expiration dates. These expenses totaled $14 million for 2001, $16 million
for 2000, and $11 million for 1999. At December 31, 2001, estimated minimum
rental commitments for these noncancelable operating leases were as follows:
Year Minimum Obligations
-----------------------
(in millions)
2002 $ 15
2003 15
2004 15
2005 15
2006 15
2007 and beyond 91
- --------------------------------------------------------------
Total $166
==============================================================
In addition to the rental commitments above, the Company has obligations upon
expiration of certain of the rail car leases with respect to the residual value
of the leased property. These leases expire in 2004 and 2010, and the Company's
maximum obligations are $13 million and $40 million, respectively. At the
termination of the leases, at the Company's option, the Company may either
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 obligation.
5. NUCLEAR INSURANCE
Under the Price-Anderson Amendments Act of 1988, 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 the
Company's nuclear power plants. The Act provides funds up to $9.5 billion for
public liability claims that could arise from a single nuclear incident. Each
nuclear plant is insured against this liability to a maximum of $200 million by
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 $88 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 for the Company, excluding any
applicable state premium taxes -- based on its ownership and buyback interests
- -- is $178 million per incident but not more than an aggregate of $20 million to
be paid for each incident in any one year.
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 between 8 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.
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
three NEIL policies would be $39 million.
29
NOTES (continued)
Georgia Power Company 2001 Annual Report
Following the terrorist attacks of September 2001, both ANI and NEIL
confirmed that terrorist acts against commercial nuclear power stations would be
covered under their insurance. Both companies, however, revised their policy
terms on a prospective basis to include an industry aggregate for all terrorist
acts. The NEIL aggregate, which applies to all claims stemming from terrorism
within a 12 month duration, is $3.24 billion plus any amounts that would be
available through reinsurance or indemnity from an outside source. The ANI cap
is $200 million in a policy year.
For all on-site property damage insurance policies for commercial nuclear
power plants, the NRC requires that the proceeds of such policies should 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.
6. JOINT OWNERSHIP AGREEMENTS
Except as otherwise noted, the Company has contracted to operate and maintain
all jointly owned generating facilities. The Company jointly owns the Rocky
Mountain pumped storage hydroelectric plant with Oglethorpe Power Company who is
the operator of the plant. The Company also jointly owns Plant McIntosh with
Savannah Electric and Power Company who operates the plant. The Company and
Florida Power Corporation (FPC) jointly own a combustion turbine unit
(Intercession City) operated by FPC.
The Company includes its proportionate share of plant operating expenses in
the corresponding operating expenses in the Statements of Income.
At December 31, 2001, the Company's percentage ownership and investment
(exclusive of nuclear fuel) in jointly owned facilities in commercial operation
were as follows:
Company Accumulated
Facility (Type) Ownership Investment Depreciation
- --------------------------------------------------------------------
(in millions)
Plant Vogtle (nuclear) 45.7% $3,304 $1,793
Plant Hatch (nuclear) 50.1 881 668
Plant Wansley (coal) 53.5 309 152
Plant Scherer (coal)
Units 1 and 2 8.4 112 56
Unit 3 75.0 545 221
Plant McIntosh
Common Facilities 75.0 24 2
(combustion-turbine)
Rocky Mountain 25.4 169 78
(pumped storage)
Intercession City 33.3 12 1
(combustion-turbine)
- --------------------------------------------------------------------
7. LONG-TERM POWER SALES AGREEMENTS
The Company and the other operating companies of Southern Company have long-term
contractual agreements for the sale of capacity and energy to certain
non-affiliated utilities located outside the system's service area. These
agreements consist of firm unit power sales pertaining to capacity from specific
generating units. Because energy is generally sold at cost under these
agreements, it is primarily the capacity revenues that affect the Company's
profitability.
The Company's capacity revenues were as follows:
Year Revenues Capacity
----------------------------------
(in millions) (megawatts)
2001 $ 26 102
2000 30 124
1999 32 162
----------------------------------
Unit power from specific generating plants is being sold to Florida Power &
Light Company, FPC, and Jacksonville Electric Authority. Under these agreements,
approximately 102 megawatts of capacity is scheduled to be sold annually for
periods after 2001 with a minimum of three years notice until the expiration of
the contracts in 2010.
8. INCOME TAXES
At December 31, 2001, tax-related regulatory assets were $544 million and
tax-related regulatory liabilities were $229 million. The assets are
30
NOTES (continued)
Georgia Power Company 2001 Annual Report
attributable to tax benefits flowed through to customers in prior years and to
taxes applicable to capitalized interest. The liabilities are attributable to
deferred taxes previously recognized at rates higher than current enacted tax
law and to unamortized investment tax credits.
Details of the federal and state income tax provisions are as follows:
2001 2000 1999
-------------------------------
Total provision for income taxes: (in millions)
Federal:
Current $352 $342 $333
Deferred (46) (34) (34)
- -----------------------------------------------------------------
306 308 299
- -----------------------------------------------------------------
State:
Current 61 48 54
Deferred (8) (5) (6)
Deferred investment tax
credits 5 10 5
- -----------------------------------------------------------------
Total $364 $361 $352
=================================================================
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:
2001 2000
-------------------
(in millions)
Deferred tax liabilities:
Accelerated depreciation $1,722 $1,755
Property basis differences 660 683
Other 295 243
- -----------------------------------------------------------------
Total 2,677 2,681
- -----------------------------------------------------------------
Deferred tax assets:
Other property basis differences 178 189
Federal effect of state deferred taxes 88 91
Other deferred costs 257 208
Other 40 37
- -----------------------------------------------------------------
Total 563 525
- -----------------------------------------------------------------
Net deferred tax liabilities 2,114 2,156
Portion included in current assets 50 27
- -----------------------------------------------------------------
Accumulated deferred income taxes
in the Balance Sheets $2,164 $2,183
=================================================================
Deferred investment tax credits are amortized over the life 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 $15 million in 2001, 2000, and 1999. At December 31, 2001, all
investment tax credits available to reduce federal income taxes payable had been
utilized.
A reconciliation of the federal statutory tax rate to the effective income
tax rate is as follows:
2001 2000 1999
--------------------------
Federal statutory rate 35% 35% 35%
State income tax, net of
federal deduction 4 4 4
Non-deductible book
depreciation 2 2 2
Other (4) (2) (2)
- ---------------------------------------------------------------
Effective income tax rate 37% 39% 39%
===============================================================
Southern Company and its subsidiaries file a consolidated federal income
tax return. Under a joint consolidated income tax agreement, each subsidiary's
current and deferred tax expense is computed on a stand-alone basis. In
accordance with Internal Revenue Service regulations, each company is jointly
and severally liable for the tax liability.
9. CAPITALIZATION
First Mortgage Bond Indenture Restrictions
The Company's first mortgage bond indenture contains various restrictions that
remain in effect as long as the bonds are outstanding. However, the Company
expects to discharge its first mortgage bond indenture by spring 2002 and to be
released from all indenture requirements. At December 31, 2001, $1.037 billion
of retained earnings and paid-in capital was unrestricted for the payment of
cash dividends or any other distributions under terms of the mortgage indenture.
The Company has no restrictions on the amount of indebtedness it may incur.
Preferred Securities
Statutory business trusts formed by the Company, of which the Company owns all
the common securities, have issued mandatorily redeemable preferred securities
as follows:
Date of Maturity
Issue Amount Rate Notes Date
---------------------------------------------------
(millions) (millions)
Trust I 8/1996 $225.00 7.75% $232 6/2036
Trust II 1/1997 175.00 7.60 180 12/2036
Trust III 6/1997 189.25 7.75 195 3/2037
Trust IV 2/1999 200.00 6.85 206 3/2029
31
NOTES (continued)
Georgia Power Company 2001 Annual Report
Substantially all of the assets of each trust are junior subordinated notes
issued by the Company in the respective approximate principal amounts set forth
above.
The Company considers that the mechanisms and obligations relating to the
preferred securities, taken together, constitute a full and unconditional
guarantee by the Company of the Trusts' payment obligations with respect to the
preferred securities.
The Trusts are subsidiaries of the Company, and accordingly are
consolidated in the Company's financial statements.
Pollution Control Bonds
The Company has incurred obligations in connection with the sale by public
authorities of tax-exempt pollution control revenue bonds. The Company has
authenticated and delivered to trustees an aggregate of $7.8 million of its
first mortgage bonds outstanding at December 31, 2001, which are pledged as
security for its obligations under pollution control revenue contracts. The
redemption of these securities will occur in March 2002.
Senior Notes
In February 2000, February 2001, and May 2001, the Company issued unsecured
senior notes. The proceeds of these issues were used to redeem higher cost
long-term debt and to reduce short-term borrowing. The senior notes are, in
effect, subordinated to all secured debt of the Company.
Bank Credit Arrangements
At the beginning of 2002, the Company had unused credit arrangements with banks
totaling $1.8 billion, of which $1.3 billion expires at various times during
2002 and $500 million expires at April 24, 2003.
Of the total $1.8 billion in unused credit, $1.65 billion is a syndicated
credit arrangement with $1.15 billion expiring April 19, 2002 and $500 million
expiring April 24, 2003. Upon expiration, the $1.15 billion agreement provides
the option of converting borrowings into two-year term loans. Both agreements
contain stated borrowing rates but also allow for competitive bid loans. In
addition, the agreements require payment of commitment fees based on the unused
portions of the commitments. Annual fees are also paid to the agent bank.
Approximately $115 million of the $1.3 billion arrangements expiring during
2002 allow for two-year term loans executable upon the expiration date of the
facilities. All of the arrangements include stated borrowing rates but also
allow for negotiated rates. These agreements also require payment of commitment
fees based on the unused portion of the commitments or the maintenance of
compensating balances with the banks. These balances are not legally restricted
from withdrawal.
This $1.8 billion in unused credit arrangements provides liquidity support
to the Company's variable rate pollution control bonds. The amount of variable
rate pollution control bonds outstanding requiring that liquidity support as of
December 31, 2001 was $984 million.
In addition, the Company borrows under uncommitted lines of credit with
banks and through commercial paper programs that has the liquidity support of
committed bank credit arrangements. Average compensating balances held under
these committed facilities were not material in 2001. The amount of commercial
paper outstanding at December 31, 2001 was $707.6 million
Other Long-Term Debt
Assets acquired under capital leases are recorded in the Balance Sheets as
utility plant in service, and the related obligations are classified as
long-term debt. At December 31, 2001 and 2000, the Company had a capitalized
lease obligation for its corporate headquarters building of $83 million with an
interest rate of 8.1 percent. For ratemaking purposes, the GPSC has treated the
lease as an operating lease and has allowed only the lease payments in cost of
service. The difference between the accrued expense and the lease payments
allowed for ratemaking purposes has been deferred and is being amortized to
expense as ordered by the GPSC. At December 31, 2001 and 2000, the interest and
lease amortization deferred on the Balance Sheets are $54 million and $55
million, respectively.
Assets Subject to Lien
The Company's mortgage dated as of March 1, 1941, 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.
32
NOTES (continued)
Georgia Power Company 2001 Annual Report
Georgia Power expects to discharge its first mortgage bond indenture by spring
2002 and that the lien will be removed.
Securities Due Within One Year
A summary of the improvement fund requirements and scheduled maturities and
redemptions of securities due within one year at December 31 is as follows:
2001 2000
------------------
(in millions)
Capital lease $ 2 $2
First mortgage bonds 2 -
Pollution control bonds 8 -
Senior notes 300 -
- ---------------------------------------------------------------
Total $312 $2
===============================================================
The Company's first mortgage bond indenture includes an improvement fund
requirement that amounts to 1 percent of each outstanding series of bonds
authenticated under the indenture prior to January 1 of each year, other than
those issued to collateralize pollution control obligations. The requirement may
be satisfied by June 1 of each year by depositing cash, reacquiring bonds, or by
pledging additional property equal to 1 2/3 times the requirement. However, the
Company expects to discharge its first mortgage bond indenture by spring 2002
and to be released from all indenture requirements.
Serial maturities through 2006 applicable to total long-term debt are as
follows: $312 million in 2002; $352 million in 2003; $2 million in 2004; $154
million in 2005; and $153 million in 2006.
10. QUARTERLY FINANCIAL DATA
(UNAUDITED)
Summarized quarterly financial information for 2001 and 2000 is as follows:
Net Income
After
Operating Operating Dividends on
Quarter Ended Revenues Income Preferred Stock
- ---------------------------------------------------------------------
(in millions)
--------------------------------------------
March 2001 $1,108 $249 $108
June 2001 1,259 322 163
September 2001 1,579 515 298
December 2001 1,020 126 41
March 2000 $ 992 $223 $ 94
June 2000 1,221 311 148
September 2000 1,545 537 283
December 2000 1,113 162 34
- ---------------------------------------------------------------------
The Company's business is influenced by seasonal weather conditions.
33
SELECTED FINANCIAL AND OPERATING DATA 1997-2001
Georgia Power Company 2001 Annual Report
- --------------------------------------------------------------------------------------------------------------------------------
2001 2000 1999 1998 1997
- --------------------------------------------------------------------------------------------------------------------------------
Operating Revenues (in thousands) $4,965,794 $4,870,618 $4,456,675 $4,738,253 $4,385,717
Net Income after Dividends
on Preferred Stock (in thousands) $610,335 $559,420 $541,383 $570,228 $593,996
Cash Dividends
on Common Stock (in thousands) $527,300 $549,600 $543,000 $536,600 $520,000
Return on Average Common Equity (percent) 14.12 13.66 14.02 14.61 14.53
Total Assets (in thousands) $13,565,941 $13,075,767 $12,361,860 $12,033,618 $12,573,728
Gross Property Additions (in thousands) $1,389,751 $1,078,163 $790,464 $499,053 $475,921
- --------------------------------------------------------------------------------------------------------------------------------
Capitalization (in thousands):
Common stock equity $4,397,485 $4,249,544 $3,938,210 $3,784,172 $4,019,728
Preferred stock 14,569 14,569 14,952 15,527 157,247
Company obligated mandatorily
redeemable preferred securities 789,250 789,250 789,250 689,250 689,250
Long-term debt 2,961,726 3,041,939 2,688,358 2,744,362 2,982,835
- --------------------------------------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) $8,163,030 $8,095,302 $7,430,770 $7,233,311 $7,849,060
================================================================================================================================
Capitalization Ratios (percent):
Common stock equity 53.9 52.5 53.0 52.3 51.2
Preferred stock 0.2 0.2 0.2 0.2 2.0
Company obligated mandatorily
redeemable preferred securities 9.6 9.7 10.6 9.5 8.8
Long-term debt 36.3 37.6 36.2 38.0 38.0
- --------------------------------------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) 100.0 100.0 100.0 100.0 100.0
================================================================================================================================
Security Ratings:
First Mortgage Bonds -
Moody's A1 A1 A1 A1 A1
Standard and Poor's A A A+ A+ A+
Fitch AA- AA- AA- AA- AA-
Preferred Stock -
Moody's Baa1 a2 a2 a2 a2
Standard and Poor's BBB+ BBB+ A- A A
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 (year-end):
Residential 1,698,407 1,669,566 1,632,450 1,596,488 1,561,675
Commercial 244,674 237,977 229,524 221,180 211,672
Industrial 8,046 8,533 8,958 9,485 9,988
Other 3,239 3,159 3,060 3,034 2,748
- --------------------------------------------------------------------------------------------------------------------------------
Total 1,954,366 1,919,235 1,873,992 1,830,187 1,786,083
================================================================================================================================
Employees (year-end): 9,048 8,860 8,961 8,371 8,354
- --------------------------------------------------------------------------------------------------------------------------------
34
SELECTED FINANCIAL AND OPERATING DATA 1997-2001 (continued)
Georgia Power Company 2001 Annual Report
- ----------------------------------------------------------------------------------------------------------------------------
2001 2000 1999 1998 1997
- ----------------------------------------------------------------------------------------------------------------------------
Operating Revenues (in thousands):
Residential $ 1,507,031 $1,535,684 $ 1,410,099 $ 1,486,699 $ 1,326,787
Commercial 1,682,918 1,620,466 1,527,880 1,591,363 1,493,353
Industrial 1,106,420 1,154,789 1,143,001 1,170,881 1,110,311
Other 52,943 6,399 (30,892) 49,274 47,848
- ----------------------------------------------------------------------------------------------------------------------------
Total retail 4,349,312 4,317,338 4,050,088 4,298,217 3,978,299
Sales for resale - non-affiliates 366,085 297,643 210,104 259,234 282,365
Sales for resale - affiliates 99,411 96,150 76,426 81,606 38,708
- ----------------------------------------------------------------------------------------------------------------------------
Total revenues from sales of electricity 4,814,808 4,711,131 4,336,618 4,639,057 4,299,372
Other revenues 150,986 159,487 120,057 99,196 86,345
- ----------------------------------------------------------------------------------------------------------------------------
Total $4,965,794 $4,870,618 $4,456,675 $4,738,253 $4,385,717
============================================================================================================================
Kilowatt-Hour Sales (in thousands):
Residential 20,119,080 20,693,481 19,404,709 19,481,486 17,295,022
Commercial 26,493,255 25,628,402 23,715,485 22,861,391 21,134,346
Industrial 25,349,477 27,543,265 27,300,355 27,283,147 26,701,685
Other 583,007 568,906 551,451 543,462 538,163
- ----------------------------------------------------------------------------------------------------------------------------
Total retail 72,544,819 74,434,054 70,972,000 70,169,486 65,669,216
Sales for resale - non-affiliates 8,110,096 6,463,723 5,060,931 6,438,891 6,795,300
Sales for resale - affiliates 3,133,485 2,435,106 1,795,243 2,038,400 1,706,699
- ----------------------------------------------------------------------------------------------------------------------------
Total 83,788,400 83,332,883 77,828,174 78,646,777 74,171,215
============================================================================================================================
Average Revenue Per Kilowatt-Hour (cents):
Residential 7.49 7.42 7.27 7.63 7.67
Commercial 6.35 6.32 6.44 6.96 7.07
Industrial 4.36 4.19 4.19 4.29 4.16
Total retail 6.00 5.80 5.71 6.13 6.06
Sales for resale 4.14 4.43 4.18 4.02 3.78
Total sales 5.75 5.65 5.57 5.90 5.80
Residential Average Annual
Kilowatt-Hour Use Per Customer 11,933 12,520 12,006 12,314 11,171
Residential Average Annual
Revenue Per Customer $893.84 $929.11 $872.48 $939.73 $857.01
Plant Nameplate Capacity
Ratings (year-end) (megawatts) 14,474 15,114 14,474 14,437 14,437
Maximum Peak-Hour Demand (megawatts):
Winter 11,977 12,014 11,568 11,959 10,407
Summer 14,294 14,930 14,575 13,923 13,153
Annual Load Factor (percent) 61.7 61.6 58.9 58.7 57.4
Plant Availability (percent):
Fossil-steam 88.5 86.1 84.3 86.0 85.8
Nuclear 94.4 91.5 89.3 91.6 88.8
- ----------------------------------------------------------------------------------------------------------------------------
Source of Energy Supply (percent):
Coal 58.5 62.3 63.0 62.3 64.3
Nuclear 18.1 17.4 18.0 18.3 18.8
Hydro 1.1 0.7 0.9 2.2 2.2
Oil and gas 0.4 1.8 1.6 2.2 0.6
Purchased power -
From non-affiliates 7.8 8.1 6.6 6.5 2.7
From affiliates 14.1 9.7 9.9 8.5 11.4
- ----------------------------------------------------------------------------------------------------------------------------
Total 100.0 100.0 100.0 100.0 100.0
============================================================================================================================
35