MANAGEMENT'S REPORT
Georgia Power Company 2000 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
Thomas A. Fanning
Executive Vice President,
Treasurer and Chief
Financial Officer
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, 2000 and 1999, and the related statements
of income, common stockholder's equity, and cash flows for each of the three
years in the period ended December 31, 2000. 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 12-32) referred to above
present fairly, in all material respects, the financial position of Georgia
Power Company as of December 31, 2000 and 1999, and the results of its
operations and its cash flows for each of the three years in the period ended
December 31, 2000, in conformity with accounting principles generally accepted
in the United States.
/s/ Arthur Andersen LLP
Atlanta, Georgia
February 28, 2001
2
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL
CONDITION
Georgia Power Company 2000 Annual Report
RESULTS OF OPERATIONS
Earnings
Georgia Power Company's 2000 earnings totaled $559 million, representing an $18
million (3.3 percent) increase over 1999. This earnings increase is 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. Georgia Power Company's 1999 earnings
totaled $541 million, representing a $29 million (5.1 percent) decrease from
1998. This earnings decrease was primarily due to the recognition of interest
income in 1998 as a result of the resolution of tax issues with the Internal
Revenue Service (IRS). Earnings in 1999 from normal operations increased due
primarily to lower accelerated depreciation under the GPSC retail rate order,
sales growth, and decreased financing costs, partially offset by retail rate
reductions under the new order and lower wholesale revenues.
Revenues
Operating revenues in 2000 and the amount of change from the prior year are as
follows:
Increase (Decrease)
From Prior Year
Amount
----------------------
2000 2000 1999
----
---------- ------------
Retail - (in millions)
Base revenues $3,119 $ 84 $(292)
Fuel cost recovery 1,198 183 44
- ---------------------------------- ---------- ---------- ------------
Total retail 4,317 267 (248)
- ---------------------------------- ---------- ---------- ------------
Sales for resale -
Non-affiliates 298 88 (49)
Affiliates 96 20 (5)
- ---------------------------------- ---------- ---------- ------------
Total sales for resale 394 108 (54)
- ---------------------------------- ---------- ---------- ------------
Other operating revenues 160 39 21
- ---------------------------------- ---------- ---------- ------------
Total operating revenues $4,871 $414 $(281)
================================== ========== ========== ============
Percent change 9.3% (5.9)%
- ---------------------------------- ---------- ---------- ------------
Retail base revenues of $3.1 billion in 2000 increased
$84 million (2.8 percent) primarily due to a 4.9 percent increase in sales.
Under the 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. Refunds will be made to customers in 2001. Retail base
revenues of $3.0 billion in 1999 decreased $292 million (8.8 percent) primarily
due to retail rate reductions under the GPSC retail rate order. Pursuant to the
GPSC retail rate order, in 1999 the Company also recorded $79 million of revenue
subject to refund for estimated earnings above 12.5 percent retail return on
common equity. Revenue subject to refund is reflected in "Base revenues" in the
chart above. The $79 million in refunds were made to customers in 2000. See Note
3 to the financial statements under "Retail Rate Order" 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, 2000, the Company had $132 million in
underrecovered fuel costs. The Company currently plans to make a filing with the
GPSC in early 2001 to establish a new fuel rate in order to better reflect
current fuel cost and to collect the current underrecovered balance.
Wholesale revenues from sales to non-affiliated utilities increased in 2000
and decreased in 1999 as follows:
2000 1999 1998
---------- --------- ----------
(in millions)
Outside service area -
Long-term contracts $ 55 $ 55 $ 51
Other sales 162 74 93
Inside service area 81 81 115
- ------------------------------- ---------- --------- ----------
Total $298 $210 $259
=============================== ========== ========= ==========
Revenues from long-term contracts outside the service area remained
constant in 2000 and increased slightly in 1999 due to increased energy sales.
See Note 7 to the financial statements for further information regarding these
sales. Revenues from other sales outside the service area primarily represent
wholesale sales from Plant Dahlberg which went into service during 2000 and
increases in power marketing activities. These activities include the purchase
and resale of energy. Consequently, changes in revenues are generally offset by
corresponding changes in purchased power expense from non-affiliates. Wholesale
3
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 2000 Annual Report
revenues from customers within the service area remained constant in 2000 but
decreased in 1999 primarily due to a decrease in revenues under a power supply
agreement with Oglethorpe Power Corporation (OPC).
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 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. In 1999,
other operating revenues increased $21 million or (21 percent) from the
previous year due primarily to increased revenues from the rental of electric
equipment and property.
Kilowatt-hour (KWH) sales for 2000 and the percent change by year were as
follows:
Percent Change
----------------------
2000
KWH 2000 1999
--------- ------------------------
(in billions)
Residential 20.7 6.6% (0.4)%
Commercial 25.6 8.1 3.7
Industrial 27.5 0.9 0.1
Other 0.6 3.2 1.5
---------
Total retail 74.4 4.9 1.1
---------
Sales for resale -
Non-affiliates 6.5 27.7 (21.4)
Affiliates 2.4 35.6 (11.9)
---------
Total sales for resale 8.9 29.8 (19.1)
---------
Total sales 83.3 7.1 (1.0)
=========
- --------------------------- --------- ---------- -----------
Residential and commercial sales increased 6.6 percent and 8.1 percent,
respectively, 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. In 1999, residential sales
decreased 0.4 percent due to moderate summer temperatures, while commercial
sales increased 3.7 percent due to strong regional economic growth. 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:
2000 1999 1998
--------- -------- ----------
Total generation
(billions of KWH) 73.6 69.3 69.1
Sources of generation
(percent) --
Coal 75.8 75.5 73.3
Nuclear 21.2 21.6 21.6
Hydro 0.8 1.0 2.6
Oil and gas 2.2 1.9 2.5
Average cost of fuel per net
KWH generated
(cents) -- 1.39 1.34 1.36
- ----------------------------------- --------- -------- ----------
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. Fuel expense increased 0.3 percent in
1999 due to a slight increase in fossil and nuclear generation and a decrease in
generation from hydro plants, partially offset by a lower average cost of fuel.
Purchased power expense in 2000 increased $206 million (53 percent) over
the prior year due to higher retail energy demands and power marketing
activities. The majority of the increase was offset by increases in retail fuel
revenues and power marketing revenues and therefore did not affect earnings. As
discussed above, the expense associated with energy purchased for power
marketing activities is generally offset by revenue when resold. Purchased power
expense decreased slightly in 1999.
Other operation and maintenance expenses in 2000 increased slightly over
those in 1999. Increased line maintenance, customer assistance and sales expense
and additional severance costs were partially offset by decreased generating
plant maintenance and decreased employee benefit provisions. Other operation and
4
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 2000 Annual Report
maintenance expenses increased 1.6 percent in 1999 primarily due to increased
generating plant maintenance, partially offset by a reduction in the charges
related to the implementation of a customer service system in 1998, decreased
year 2000 readiness costs, and decreased employee benefit provisions.
Depreciation and amortization increased $66 million in 2000 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. Depreciation and amortization decreased $261 million in 1999 primarily
due to higher depreciation charges recognized in 1998 under the prior GPSC
accounting order and the completion in 1998 of the amortization of deferred
Plant Vogtle costs.
Interest income decreased $3 million in 2000 primarily due to decreased
interest on temporary cash investments. Interest income decreased in 1999
primarily due to the 1998 recognition of $73 million in interest income
resulting from the resolution of tax issues with the IRS and the State of
Georgia. Other, net decreased in 2000 due to an increase in charitable
contributions. In 1999, other, net decreased due primarily to increased bad debt
expense related to consumer energy efficiency improvement financing.
Interest expense, net increased in 2000 due to the issuance of an
additional $300 million in senior notes during 2000. Interest expense, net
decreased in 1999 due primarily to the refinancing or retirement of securities.
The Company refinanced or retired $179 million and $775 million of securities in
2000 and 1999, respectively. Distributions on preferred securities of subsidiary
companies decreased $7 million in 2000 due to the redemption of $100 million of
preferred securities in December 1999. Distributions on preferred securities of
subsidiary companies increased $11 million in 1999 due to the issuance of
additional mandatorily redeemable preferred securities in January 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 life. 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
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.
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 January 1, 1999, the Company began operating under a new three-year
retail rate order. The Company's earnings are evaluated against a retail return
on common equity range of 10 percent to 12.5 percent, with required rate
reductions of $262 million on an annual basis effective in 1999 and an
additional $24 million effective in 2000. The order provides 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 will be applied to rate reductions, with the remaining one-third
retained by the Company. Pursuant to the GPSC retail rate order, in 2000 and
1999, the Company recorded $85 million in accelerated amortization of regulatory
assets. In 2000, the Company also recorded the additional $50 million of
accelerated amortization. The accelerated amortization is recorded in a
regulatory liability account as mandated by the GPSC. In addition, the Company
recorded $44 million and $79 million of revenue subject to refund for estimated
earnings above 12.5 percent in 2000 and 1999, respectively. Refunds applicable
to 1999 were made to customers in 2000. The Company will file a general rate
case on July 2, 2001 in response to which the GPSC would be expected to
5
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 2000 Annual Report
determine whether the retail rate order should be continued, modified, or
discontinued. See Note 3 to the financial statements under "Retail Rate Order"
for additional information.
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. Assuming normal weather,
retail sales growth from 2000 is projected to be approximately 2.4 percent
annually on average during 2001 through 2003.
The Company has entered into purchase power agreements which will result in
higher capacity and operating and maintenance payments in future years. See Note
4 to the financial statements under "Purchased Power Commitments" for additional
information.
The Company is constructing two 566 megawatt combined cycle units at Plant
Wansley to begin operation in 2002. These units have been certified by the GPSC
to serve the Company's retail customers for approximately seven years. Savannah
Electric will have the rights to 200 megawatts of capacity from these units for
the same seven-year period.
The Company is also constructing a 571 megawatt combined cycle unit at
Plant Goat Rock to begin operation in 2002, and a 610 megawatt combined cycle
unit at Plant Goat Rock to begin operation in 2003. The power from these units
will initially be sold into the wholesale market when they begin operation. The
Company has filed with the GPSC for certification of these units to begin
serving the Company's retail customers in 2003 and 2004, respectively, for a
term of seven years each.
In addition to seeking certification of Plant Goat Rock, the Company is
also seeking certification of a seven year commitment to 615 megawatts beginning
in 2004 at Plant Autaugaville to serve its retail customers. Plant Autaugaville
is currently under construction by Alabama Power.
Further, the Company is constructing Plant Dahlberg, a ten unit, 800
megawatt combustion turbine peaking power plant that will serve the wholesale
market. Units one through eight began operation in May 2000; units nine and ten
are expected to begin operation in June 2001. The Company has entered into
wholesale contracts to sell all 800 megawatts of capacity. These contracts cover
substantially all of the output of the plant for the first five years. Because
these units are dedicated to the wholesale market, retail rates will not be
affected.
The Company is aggressively working to maintain and expand its share of
wholesale sales in the Southeastern power markets. In January 2001, Southern
Company announced the formation of a new subsidiary, Southern Power Company
(SPC). SPC will own, manage, and finance wholesale generating assets in the
Southeast. Energy from its assets will be marketed to wholesale customers under
the Southern Company name. The current plan is for Georgia Power and Alabama
Power to transfer Plant Dahlberg and the units under construction at Plants
Wansley, Goat Rock, and Autaugaville to SPC in 2001. The Company will enter into
purchased power capacity agreements with SPC for power from the units at Plants
Wansley, Goat Rock, and Autaugaville to serve the Company's retail customers.
In accordance with Financial Accounting Standards Board (FASB) Statement
No. 87, Employers' Accounting for Pensions, the Company recorded non-cash income
of approximately $59 million in 2000. Pension plan income in 2001 is expected to
be less as a result of plan amendments. Future pension income is dependent on
several factors including trust earnings and changes to the plan. For additional
information see Note 2 to the financial statements.
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.
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. Although the Energy Act
6
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 2000 Annual Report
does not permit retail customer access, it was a major catalyst for the current
restructuring and consolidation taking place within the utility industry.
On December 20, 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. After participating in regional conferences with customers and other
members of the public to discuss the formation of RTOs, utilities were required
to make a filing with the FERC. On October 16, 2000, Southern Company and its
five integrated Southeast utilities, including the Company, filed with the FERC
a proposal for the creation of an RTO. The proposal is for the formation of a
for-profit company that would have control of the bulk power transmission system
of participating utilities. Participants would have the option to either
maintain their ownership, divest, sell, or lease their assets to the proposed
RTO. If the FERC accepts the proposal as filed, the creation of the RTO is not
expected to have a material impact on the financial statements of the Company.
However, the ultimate outcome of this matter cannot now be determined.
The Company continues to 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. Numerous federal and state
initiatives are in varying stages to promote wholesale and retail competition
across the nation. Among other things, these initiatives allow customers to
choose their electricity provider. As these initiatives materialize, the
structure of the utility industry could radically change. 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 the GPSC has held workshops to
discuss retail competition and industry restructuring, there has been no
proposed or enacted legislation to date in Georgia. Enactment would require
numerous issues to be resolved, including significant ones relating to
transmission pricing and recovery of costs. The GPSC continues its assessment of
the range of potential stranded costs. The inability of the Company to recover
all its costs, including the regulatory assets described in Note 1 to the
financial statements, could have a material effect on the financial condition of
the Company. The Company is attempting to reduce regulatory assets through the
GPSC retail rate order. See Note 3 to the financial statements under "Retail
Rate Order" for additional information.
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 have been impaired. See Note 1 to the financial statements under
"Regulatory Assets and Liabilities" for additional information.
The staff of the Securities and Exchange Commission (SEC) has questioned
certain of the current accounting practices of the electric utility industry -
including the Company's - regarding the recognition, measurement, and
classification in the financial statements of decommissioning costs for nuclear
generating facilities. In response to these questions, the FASB is reviewing the
accounting for liabilities related to the retirement of long-lived assets,
including nuclear decommissioning. If the FASB issues new accounting rules, the
estimated costs of retiring the Company's nuclear and other facilities may be
required to be recorded as liabilities in the Balance Sheets. Also, the annual
provisions for such costs could change. Because of the Company's current ability
to recover asset retirement costs through rates, these changes would not have a
significant adverse effect on results of operations. See Note 1 to the financial
statements under "Depreciation and Nuclear Decommissioning" for additional
information.
Exposure to Market Risks
Due to cost-based rate regulation, the Company currently has limited exposure to
market volatility in interest rates, commodity fuel prices and prices of
electricity. (See the discussion above for potential changes in industry
structure.) To mitigate residual risks relative to movements in electricity
prices, the Company enters into fixed price contracts for the purchase and sale
of electricity through the wholesale electricity market. Realized gains and
losses are recognized in the income statement as incurred. At December 31, 2000,
exposure from these activities was not material to the Company's financial
position, results of operations, or cash flows. Also, based on the Company's
overall interest rate exposure at December 31, 2000, a near-term 100 basis point
7
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 2000 Annual Report
change in interest rates would not materially affect the financial statements.
New Accounting Standard
In June 2000, the FASB issued Statement No. 138, an amendment of Statement
No. 133, Accounting for Derivative Instruments and Hedging Activities. Statement
No. 133, as amended, establishes accounting and reporting standards for
derivative instruments and for hedging activities. Statement No. 133 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.
Substantially all of the Company's bulk energy purchases and sales meet the
definition of a derivative under Statement No. 133. In many cases, these
transactions meet the normal purchase and sale exception and the related
contracts will continue to be accounted for under the accrual method. Certain of
these instruments qualify as cash flow hedges resulting in the deferral of
related gains and losses in other comprehensive income until the hedged
transactions occur. Any ineffectiveness will be recognized currently in net
income. However, others will be required to be marked to market through current
period income.
The Company adopted the provisions of Statement No. 133 effective January
1, 2001. The impact on net income was immaterial. The application of the new
rules is still evolving and further guidance from the FASB is expected, which
could additionally impact the Company's financial statements.
FINANCIAL CONDITION
Plant Additions
In 2000, gross utility plant additions were $1.1 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.
Financing Activities
In 2000, the Company's financing costs increased due to the issuance of new debt
during the year. New issues during 1998 through 2000 totaled $1.5 billion and
retirement or repayment of higher-cost securities totaled $1.7 billion.
Special purpose subsidiaries of the Company have issued mandatorily
redeemable preferred securities. See Note 9 to the financial statements under
"Preferred Securities" for additional information.
Composite financing rates for long-term debt, preferred stock, and
preferred securities for the years 1998 through 2000, as of year-end, were as
follows:
2000 1999 1998
----------- ---------- -----------
Composite interest rate
on long-term debt 5.90% 5.48% 5.64%
Composite preferred
stock dividend rate 4.60 4.60 5.52
Composite preferred
securities dividend rate 7.49 7.49 7.89
- ------------------------------- ----------- ---------- -----------
Liquidity and Capital Requirements
Cash provided from operations decreased by $135 million in 2000, primarily due
to higher fuel and purchased power expenses related to increased energy demands.
The Company estimates that construction expenditures for the years 2001
through 2003 will total $1.6 billion, $1.3 billion, and $0.8 billion,
respectively. If the Company transfers wholesale generation assets to SPC in
2001 as contemplated, construction expenditures for the years 2001 through 2003
will total $1.0 billion, $0.9 billion, and $0.7 billion, respectively.
Investments in additional combustion turbine and combined cycle generating
units, transmission and distribution facilities, enhancements to existing
generating plants, and equipment to comply with environmental requirements are
planned.
Cash requirements for redemptions announced and maturities of long-term
debt are expected to total $581 million during 2001 through 2003.
As a result of requirements by the Nuclear Regulatory Commission, the
Company has established external trust funds for the purpose of funding nuclear
8
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 2000 Annual Report
decommissioning costs. The amount to be funded is $30 million each year in 2001,
2002, and 2003. 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, if needed,
by the issuance of new debt and equity securities, term loans, and short-term
borrowings. 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 2001. See Note 9 to the financial statements under "Bank Credit
Arrangements" for additional information.
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 the later securities has been steadily
declining during the last four years.
If the Company were to choose to issue new first mortgage bonds or
preferred stock once again, it would be required to meet certain coverage
requirements.
ENVIRONMENTAL ISSUES
Clean Air Act
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. Specific reductions in sulfur dioxide and nitrogen oxide
emissions from fossil-fired generating plants are required in two phases. Phase
I compliance began in 1995 and some 50 generating units within Southern
Company's subsidiaries were brought into compliance with Phase I requirements.
Southern Company's subsidiaries, including the Company, achieved Phase I
sulfur dioxide compliance at the affected units by switching to low-sulfur coal,
which required 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.
The one-hour ozone non-attainment standards for the Atlanta area have been
set and must be implemented in May 2003. Seven generating plants will be
affected in the Atlanta area. Additional construction expenditures for the
Company's compliance with these new rules are currently estimated at
approximately $705 million.
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.
9
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 2000 Annual Report
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 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 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. 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 unless such costs can be recovered through regulated rates.
Other Environmental Issues
In July 1997, the 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 recently dismissed certain challenges but 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
will address other legal challenges to these standards in mid-2001. If the
standards are eventually upheld, implementation could be required by 2007 to
2010.
In September 1998, the EPA issued the final regional nitrogen oxide
reduction rules to the states for implementation. Compliance is required by May
31, 2004. The final rule affects 21 states, including Georgia.
In December 2000, the EPA completed its utility study for mercury and other
hazardous air pollutants (HAPS) and issued a determination that an emission
control program for mercury and, perhaps, other HAPS is warranted. The program
is to be developed over the next four years under the Maximum Achievable Control
Technology (MACT) provisions of the Clean Air Act. This determination is being
challenged in the courts. 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 would likely
be required around 2010. Litigation of the BART rules is probable in the near
future.
Implementation of the final state rules for these initiatives could require
substantial further reductions in nitrogen oxide, sulfur dioxide, 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. Reviews by the new administration in Washington, D.C.
add to the uncertainties associated with BART guidance and the MACT
determination for mercury and other HAPS.
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 costs and has recognized in the financial statements costs to
clean up known sites. These costs for the Company amounted to $4 million, $4
million, and $6 million in 2000, 1999, and 1998, respectively. Additional sites
may require environmental remediation for which the Company may be liable for a
portion of or all 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 a site in Brunswick,
Georgia, and the status of sites listed on the State of Georgia's hazardous site
inventory.
10
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 2000 Annual Report
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; water intake
restrictions; and hazardous waste disposal requirements. The impact of any new
standards will depend on the development and implementation of applicable
regulations.
Several major pieces of environmental legislation are being 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 2000 Annual Report contains forward-looking and historical
information. In some cases, forward-looking statements can be identified by
terminology such as "may," "will," "should," "expects," "plans," "anticipates,"
"believes," "estimates," "predicts," "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 extent and timing of the
entry of additional competition in the Company's markets; potential business
strategies, including acquisitions or dispositions of assets or businesses,
which cannot be assured to be completed or beneficial; internal restructuring or
other restructuring options, that may be pursued by the Company; state and
federal rate regulation in the United States; political, legal and economic
conditions and developments in the United States; financial market conditions
and the results of financing efforts; the impact of fluctuations in commodity
prices, interest rates and customer demand; weather and other natural phenomena;
the ability of the Company to obtain additional generating capacity at
competitive prices; and other factors discussed elsewhere herein and in other
reports (including Form 10-K) filed from time to time by the Company with the
SEC.
11
STATEMENTS OF INCOME
For the Years Ended December 31, 2000, 1999, and 1998
Georgia Power Company 2000 Annual Report
- ------------------------------------------------------------------------------------------------------------
2000 1999 1998
- ------------------------------------------------------------------------------------------------------------
(in thousands)
Operating Revenues:
Retail sales $4,317,338 $4,050,088 $4,298,217
Sales for resale --
Non-affiliates 297,643 210,104 259,234
Affiliates 96,150 76,426 81,606
Other revenues 159,487 120,057 99,196
- ------------------------------------------------------------------------------------------------------------
Total operating revenues 4,870,618 4,456,675 4,738,253
- ------------------------------------------------------------------------------------------------------------
Operating Expenses:
Operation --
Fuel 1,017,878 919,876 917,119
Purchased power --
Non-affiliates 356,189 214,573 229,960
Affiliates 239,815 174,989 161,003
Other 795,458 784,359 819,589
Maintenance 404,189 411,983 358,218
Depreciation and amortization 619,094 552,966 813,802
Taxes other than income taxes 204,527 202,853 204,623
Write down of Rocky Mountain plant - - 33,536
- ------------------------------------------------------------------------------------------------------------
Total operating expenses 3,637,150 3,261,599 3,537,850
- ------------------------------------------------------------------------------------------------------------
Operating Income 1,233,468 1,195,076 1,200,403
Other Income (Expense):
Interest income 2,629 5,583 79,578
Equity in earnings of unconsolidated subsidiaries 3,051 2,721 3,735
Other, net (50,495) (47,986) (38,277)
- ------------------------------------------------------------------------------------------------------------
Earnings Before Interest and Income Taxes 1,188,653 1,155,394 1,245,439
- ------------------------------------------------------------------------------------------------------------
Interest Charges and Other:
Interest expense, net 208,868 194,869 216,313
Distributions on preferred securities of subsidiaries 59,104 65,774 54,327
- ------------------------------------------------------------------------------------------------------------
Total interest charges and other, net 267,972 260,643 270,640
- ------------------------------------------------------------------------------------------------------------
Earnings Before Income Taxes 920,681 894,751 974,799
Income taxes 360,587 351,639 398,632
- ------------------------------------------------------------------------------------------------------------
Net Income 560,094 543,112 576,167
Dividends on Preferred Stock 674 1,729 5,939
- ------------------------------------------------------------------------------------------------------------
Net Income After Dividends on Preferred Stock $ 559,420 $ 541,383 $ 570,228
============================================================================================================
The accompanying notes are an integral part of these statements.
12
STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2000, 1999, and 1998
Georgia Power Company 2000 Annual Report
- -------------------------------------------------------------------------------------------------------------------------------
2000 1999 1998
- -------------------------------------------------------------------------------------------------------------------------------
(in thousands)
Operating Activities:
Net income $ 560,094 $ 543,112 $ 576,167
Adjustments to reconcile net income to net
cash provided from operating activities --
Depreciation and amortization 712,960 663,878 867,637
Deferred income taxes and investment tax credits, net (28,961) (34,930) (93,005)
Other, net (51,501) (42,179) 40,396
Changes in certain current assets and liabilities --
Receivables, net (108,621) 21,665 (25,453)
Fossil fuel stock 26,835 (22,165) (8,066)
Materials and supplies (9,715) (10,417) (3,090)
Accounts payables 64,412 13,095 47,862
Energy cost recovery, retail (95,235) (26,862) (7,649)
Other (9,092) 90,788 6,997
- -------------------------------------------------------------------------------------------------------------------------------
Net cash provided from operating activities 1,061,176 1,195,985 1,401,796
- -------------------------------------------------------------------------------------------------------------------------------
Investing Activities:
Gross property additions (1,078,163) (790,464) (499,053)
Other (5,450) (27,454) 67,031
- -------------------------------------------------------------------------------------------------------------------------------
Net cash used for investing activities (1,083,613) (817,918) (432,022)
- -------------------------------------------------------------------------------------------------------------------------------
Financing Activities:
Increase (decrease) in notes payable, net 67,598 295,389 (25,378)
Proceeds --
Senior notes 300,000 100,000 495,000
Pollution control bonds 78,725 238,000 89,990
Preferred securities - 200,000 -
Capital contributions from parent company 301,514 155,777 235
Retirements --
First mortgage bonds (100,000) (404,000) (558,250)
Pollution control bonds (78,725) (235,000) (89,990)
Preferred securities - (100,000) -
Preferred stock (383) (36,231) (106,064)
Capital distributions to parent company - - (270,000)
Payment of preferred stock dividends (751) (984) (9,137)
Payment of common stock dividends (549,600) (543,000) (536,600)
Other (1,231) (29,630) (26,641)
- -------------------------------------------------------------------------------------------------------------------------------
Net cash provided from (used for) financing activities 17,147 (359,679) (1,036,835)
- -------------------------------------------------------------------------------------------------------------------------------
Net Change in Cash and Cash Equivalents (5,290) 18,388 (67,061)
Cash and Cash Equivalents at Beginning of Year 34,660 16,272 83,333
- -------------------------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of Year $29,370 $34,660 $16,272
- -------------------------------------------------------------------------------------------------------------------------------
Supplemental Cash Flow Information:
Cash paid during the year for --
Interest (net of amount capitalized) $ 265,373 $ 247,050 $ 269,524
Income taxes (net of refunds) 392,310 394,457 480,318
- -------------------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these statements.
13
BALANCE SHEETS
At December 31, 2000 and 1999
Georgia Power Company 2000 Annual Report
- ------------------------------------------------------------------------------------------------------------------------------------
Assets 2000 1999
- ------------------------------------------------------------------------------------------------------------------------------------
(in thousands)
Current Assets:
Cash and cash equivalents $ 29,370 $ 34,660
Receivables --
Customer accounts receivable 465,249 401,773
Unrecovered retail fuel clause revenue 131,623 36,388
Other accounts and notes receivable 156,143 102,544
Affiliated companies 13,312 16,006
Accumulated provision for uncollectible accounts (5,100) (7,000)
Fossil fuel stock, at average cost 99,463 126,298
Materials and supplies, at average cost 263,609 253,894
Other 97,515 63,990
- ------------------------------------------------------------------------------------------------------------------------------------
Total current assets 1,251,184 1,028,553
- ------------------------------------------------------------------------------------------------------------------------------------
Property, Plant, and Equipment:
In service 16,469,706 15,798,624
Less accumulated provision for depreciation 6,914,512 6,538,574
- ------------------------------------------------------------------------------------------------------------------------------------
9,555,194 9,260,050
Nuclear fuel, at amortized cost 120,570 119,288
Construction work in progress (Note 4) 652,264 425,975
- ------------------------------------------------------------------------------------------------------------------------------------
Total property, plant, and equipment 10,328,028 9,805,313
- ------------------------------------------------------------------------------------------------------------------------------------
Other Property and Investments:
Equity investments in unconsolidated subsidiaries (Note 4) 25,485 25,024
Nuclear decommissioning trusts 375,666 371,914
Other 33,829 33,766
- ------------------------------------------------------------------------------------------------------------------------------------
Total other property and investments 434,980 430,704
- ------------------------------------------------------------------------------------------------------------------------------------
Deferred Charges and Other Assets:
Deferred charges related to income taxes (Note 8) 565,982 590,893
Prepaid pension costs 205,113 145,801
Debt expense, being amortized 53,748 55,824
Premium on reacquired debt, being amortized 173,610 184,331
Other 120,964 120,441
- ------------------------------------------------------------------------------------------------------------------------------------
Total deferred charges and other assets 1,119,417 1,097,290
- ------------------------------------------------------------------------------------------------------------------------------------
Total Assets $13,133,609 $12,361,860
====================================================================================================================================
The accompanying notes are an integral part of these balance sheets.
14
BALANCE SHEETS
At December 31, 2000 and 1999
Georgia Power Company 2000 Annual Report
- ---------------------------------------------------------------------------------------------------------------
Liabilities and Stockholder's Equity 2000 1999
- ---------------------------------------------------------------------------------------------------------------
(in thousands)
Current Liabilities:
Securities due within one year (Note 9) $ 1,808 $ 155,772
Notes payable 703,839 636,241
Accounts payable --
Affiliated 117,168 76,591
Other 397,550 346,785
Customer deposits 78,540 74,695
Taxes accrued --
Income taxes 5,151 7,914
Other 137,511 127,414
Interest accrued 47,244 58,665
Vacation pay accrued 38,865 38,143
Other 153,400 153,767
- ---------------------------------------------------------------------------------------------------------------
Total current liabilities 1,681,076 1,675,987
- ---------------------------------------------------------------------------------------------------------------
Long-term debt (See accompanying statements) 3,041,939 2,688,358
- ---------------------------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes (Note 8) 2,182,783 2,202,565
Deferred credits related to income taxes (Note 8) 247,067 267,083
Accumulated deferred investment tax credits (Note 8) 352,282 367,114
Employee benefits provisions 177,444 181,529
Other 397,655 236,812
- ---------------------------------------------------------------------------------------------------------------
Total deferred credits and other liabilities 3,357,231 3,255,103
- ---------------------------------------------------------------------------------------------------------------
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 14,952
- ---------------------------------------------------------------------------------------------------------------
Common stockholder's equity (See accompanying statements) 4,249,544 3,938,210
- ---------------------------------------------------------------------------------------------------------------
Total Liabilities and Stockholder's Equity $13,133,609 $12,361,860
===============================================================================================================
The accompanying notes are an integral part of these balance sheets.
15
STATEMENTS OF CAPITALIZATION
At December 31, 2000 and 1999
Georgia Power Company 2000 Annual Report
- ----------------------------------------------------------------------------------------------------------------------------------
2000 1999 2000 1999
- ----------------------------------------------------------------------------------------------------------------------------------
(in thousands) (percent of total)
Long-Term Debt:
First mortgage bonds --
Maturity Interest Rates
March 1, 2000 6.00% $ - $ 100,000
April 1, 2003 6.625% 200,000 200,000
August 1, 2003 6.35% 75,000 75,000
2005 6.07% 10,000 10,000
2008 6.875% 50,000 50,000
2025 7.70% 57,000 57,000
- ----------------------------------------------------------------------------------------------------------------
Total first mortgage bonds 392,000 492,000
- ----------------------------------------------------------------------------------------------------------------
Senior notes -- (Note 9)
Variable rate (6.71375% at 1/1/01) due February 22, 2002 300,000 -
5.50% due December 1, 2005 150,000 150,000
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 895,000 595,000
- ----------------------------------------------------------------------------------------------------------------
Other long-term debt -- (Note 9)
Pollution control revenue bonds --
Maturity Interest Rates
2000 4.375% - 50,000
2005 5.00% 57,000 57,000
2011 Variable (5.10% at 1/1/01) 10,450 10,450
2018-2019 6.00% to 6.25% 13,100 13,100
2021-2025 5.40% to 6.75% 308,660 337,385
2022-2025 Variable (4.85% to 5.35% at 1/1/01) 622,075 622,075
2026-2030 Variable (5.00% to 5.10% at 1/1/01) 206,180 206,180
2030 4.53% 78,725 -
2032-2034 Variable (5.0% to 5.30% at 1/1/01) 140,000 140,000
2034 5.25% to 5.45% 238,000 238,000
- ----------------------------------------------------------------------------------------------------------------
Total other long-term debt 1,674,190 1,674,190
- ----------------------------------------------------------------------------------------------------------------
Capital lease obligations (Note 9) 85,179 85,851
- ----------------------------------------------------------------------------------------------------------------
Unamortized debt discount, net (2,622) (2,911)
- ----------------------------------------------------------------------------------------------------------------
Total long-term debt (annual interest
requirement -- $179.6 million) 3,043,747 2,844,130
Less amount due within one year (Note 9) 1,808 155,772
- -----------------------------------------------------------------------------------------------------------------------------------
Total long-term debt excluding amount due within one year $ 3,041,939 $ 2,688,358 37.6 % 36.2 %
- -----------------------------------------------------------------------------------------------------------------------------------
16
STATEMENTS OF CAPITALIZATION (continued)
At December 31, 2000 and 1999
Georgia Power Company 2000 Annual Report
- -----------------------------------------------------------------------------------------------------------------------------------
2000 1999 2000 1999
- -----------------------------------------------------------------------------------------------------------------------------------
(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 9.7 10.6
- -----------------------------------------------------------------------------------------------------------------------------------
Cumulative Preferred Stock, without par value:
Authorized -- 55,000,000 shares
Outstanding -- 145,689 shares at December 31, 2000
Outstanding -- 149,520 shares at December 31, 1999
$100 stated value --
4.60% 14,569 14,952
- -----------------------------------------------------------------------------------------------------------------------------------
Total cumulative preferred stock (annual dividend
requirement -- $0.7 million) 14,569 14,952 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 2,117,497 1,815,983
Premium on preferred stock 40 40
Retained earnings (Note 9) 1,787,757 1,777,937
- -----------------------------------------------------------------------------------------------------------------------------------
Total common stockholder's equity (See accompanying statements) 4,249,544 3,938,210 52.5 53.0
- -----------------------------------------------------------------------------------------------------------------------------------
Total Capitalization $ 8,095,302 $ 7,430,770 100.0 % 100.0 %
- -----------------------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these statements.
17
STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
For the Years Ended December 31, 2000, 1999, and 1998
Georgia Power Company 2000 Annual Report
- --------------------------------------------------------------------------------------------------------------------------------
Premium on
Common Paid-In Preferred Retained
Stock Capital Stock Earnings Total
- --------------------------------------------------------------------------------------------------------------------------------
(in thousands)
Balance at January 1, 1998 $344,250 $1,929,971 $160 $1,745,347 $4,019,728
Net income after dividends on preferred stock - - - 570,228 570,228
Capital distributions to parent company - (270,000) - - (270,000)
Capital contributions from parent company - 235 - - 235
Cash dividends on common stock - - - (536,600) (536,600)
Preferred stock transactions, net - - (2) 583 581
- --------------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 1998 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
================================================================================================================================
The accompanying notes are an integral part of these statements.
18
NOTES TO FINANCIAL STATEMENTS
Georgia Power Company 2000 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 integrated Southeast utilities, Southern Company Services
(SCS), the system service company, Southern Communications Services (Southern
LINC), Mirant Corporation (formerly Southern Energy), Southern Nuclear Operating
Company (Southern Nuclear), Southern Company Energy Solutions, and other direct
and indirect subsidiaries. The integrated Southeast utilities (Alabama Power
Company, Georgia Power Company, Gulf Power Company, Mississippi Power Company,
and Savannah Electric and Power Company) provide electric service in four
states. Contracts among the integrated Southeast utilities -- related to jointly
owned generating facilities, interconnecting transmission lines, and the
exchange of electric power -- are regulated by the Federal Energy Regulatory
Commission (FERC) or the Securities and Exchange Commission (SEC). SCS provides,
at cost, specialized services to Southern Company and subsidiary companies.
Southern LINC provides digital wireless communications services to the
subsidiary companies and also markets these services to the public within the
Southeast. Southern Company Energy Solutions develops new business opportunities
related to energy products and services. Southern Nuclear provides services to
Southern Company's nuclear power plants. Mirant Corporation acquires, develops,
builds, owns, and operates power production and delivery facilities and provides
a broad range of energy-related services to utilities and industrial companies
in selected countries around the world. Mirant Corporation's businesses include
independent power projects, integrated utilities, a distribution company, and
energy trading and marketing businesses outside the Southeastern United States.
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.
Related-Party 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 $269 million, $253
million, and $251 million during 2000, 1999, and 1998, 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, $270 million, and
$269 million during 2000, 1999, and 1998, respectively.
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. Pursuant to the terms of the GPSC
retail rate order, the Company recorded $135 million and $85 million in 2000 and
1999, respectively, of accelerated cost recovery of regulatory assets which have
19
NOTES (continued)
Georgia Power Company 2000 Annual Report
been recorded on the balance sheet as a regulatory liability. See Note 3 under
"Retail Rate Order" for additional information. Regulatory assets and
(liabilities) reflected in the Company's Balance Sheets at December 31 relate to
the following:
2000 1999
----------------------
(in millions)
Deferred income taxes $ 566 $ 591
Deferred income tax credits (247) (267)
Premium on reacquired debt 174 184
Corporate building lease 55 54
Vacation pay 49 47
Postretirement benefits 30 33
Department of Energy assessments 21 24
Deferred nuclear outage costs 28 26
Accelerated cost recovery (220) (85)
Interest, accelerated cost recovery (10) -
Other, net 23 3
- ------------------------------------------ ---------- ---------
Total $ 469 $ 610
========================================== ========== =========
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.
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.
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.
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 2000, $74 million in 1999, and $74 million in 1998. The Company has a
contract with the U.S. Department of Energy (DOE) that provides for the
permanent disposal of spent nuclear fuel. The DOE failed to begin disposing of
spent fuel in January 1998 as required by the contracts, and the Company is
pursuing legal remedies against the government for breach of contract. Effective
June 2000, the on-site dry storage facility for Plant Hatch became operational.
Sufficient capacity is believed available to continue dry storage operations at
Plant Hatch through the life of the plant. Sufficient fuel storage capacity
currently is available at Plant Vogtle to maintain full-core discharge
capability for both units into the year 2014.
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, 2000 to be approximately $19 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 2000 and 1999, and 3.2 percent in 1998. In addition, pursuant to
a GPSC retail rate order, the Company recorded accelerated depreciation of
electric plant of $304 million in 1998. Total accelerated depreciation recorded
under the GPSC retail rate order was $467 million. These charges are recorded in
the accumulated provision for depreciation. When property subject to
depreciation is retired or otherwise disposed of in the normal course of
20
NOTES (continued)
Georgia Power Company 2000 Annual Report
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
reasonable assurance, funds for decommissioning. The Company has established
external trust funds to comply with the NRC's regulations. Amounts previously
recorded in internal reserves are being transferred into the external trust
funds over a set period of time as ordered by the GPSC. 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. The Company
has filed with the NRC an application requesting a 20-year renewal of the
licenses for both units at Plant Hatch which would permit the operation of both
units until 2034.
Annual provisions for nuclear decommissioning expense are based on an
annuity method as approved by the GPSC. The amounts expensed in 2000 and fund
balances as of December 31, 2000 were:
Plant Plant
Hatch Vogtle
- ----------------------------------------- ------------ ---------
(in millions)
Amount expensed in 2000 $ 19 $ 9
========================================= ============ =========
(in millions)
Accumulated provisions:
External trust funds, at fair value $230 $146
Internal reserves 20 12
- ----------------------------------------- ------------ ---------
Total $250 $158
========================================= ============ =========
Effective January 1, 1999, the GPSC increased the annual provision for
decommissioning expenses to $28 million from $20 million in 1998. This amount
is based on the NRC generic estimate to decommission the radioactive
21
NOTES (continued)
Georgia Power Company 2000 Annual Report
portion of the facilities as of 1997 of $526 million and $438 million for
Plants Hatch and Vogtle, respectively. The ultimate costs associated with the
1997 NRC minimum funding requirements are $1.1 billion and $1.3 billion for
Plants Hatch and Vogtle, respectively. Significant assumptions include an
estimated inflation rate of 3.6 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.
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
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 2000, 1999, and 1998, the average AFUDC
rates were 6.74 percent, 5.61 percent, and 6.71 percent, respectively. AFUDC,
net of taxes, as a percentage of net income after dividends on preferred stock,
was less than 2.0 percent for 2000, 1999 and 1998.
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.
Financial Instruments
The Company has a firm commitment that requires payment in euros. As a hedge
against fluctuations in the exchange rate for euros, the Company entered into
forward currency swaps. The notional amount is 15.9 million euros maturing in
2001 through 2002. At December 31, 2000, the unrecognized gain on these swaps
was approximately $1.3 million.
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, 2000 $2,959 $ 2,912
At December 31, 1999 $2,758 $2,604
Preferred securities:
At December 31, 2000 $789 $761
At December 31, 1999 $789 $680
- ------------------------------------- ------------- ----------
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
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 FERC. In late 2000, the Company
adopted several pension and postretirement benefits plan changes that had the
22
NOTES (continued)
Georgia Power Company 2000 Annual Report
effect of increasing benefits to both current and future retirees. The effects
of these changes will be to increase annual pension and postretirement benefits
costs by approximately $10 million and $6 million, respectively. 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:
2000 1999
- -------------------------------------------- --------- ----------
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
---------------------------
2000 1999
- ------------------------------------ ------------- -------------
(in millions)
Balance at beginning of year $1,205 $1,217
Service cost 32 33
Interest cost 88 80
Benefits paid (58) (57)
Actuarial gain and
employee transfers (14) (68)
- ------------------------------------ ------------- -------------
Balance at end of year $1,253 $1,205
==================================== ============= =============
Plan Assets
---------------------------
2000 1999
- ------------------------------------ ------------- -------------
(in millions)
Balance at beginning of year $2,107 $1,859
Actual return on plan assets 385 313
Benefits paid (58) (57)
Employee transfers 30 (8)
- ------------------------------------ ------------- -------------
Balance at end of year $2,464 $2,107
==================================== ============= =============
The accrued pension costs recognized in the Balance Sheets were as follows:
2000 1999
- ------------------------------------------ --------- ----------
(in millions)
Funded status $ 1,211 $ 902
Unrecognized transition obligation (26) (30)
Unrecognized prior service cost 38 41
Unrecognized net actuarial gain (1,018) (767)
- ------------------------------------------ --------- ----------
Prepaid asset recognized in the
Balance Sheets $ 205 $ 146
========================================== ========= ==========
Components of the plan's net periodic cost were as follows:
2000 1999 1998
- ------------------------------------- ------- -------- --------
(in millions)
Service cost $ 32 $ 33 $ 30
Interest cost 88 80 82
Expected return on plan assets (151) (137) (127)
Recognized net actuarial gain (27) (17) (20)
Net amortization (1) (1) (1)
- ------------------------------------- ------- -------- --------
Net pension income $ (59) $ (42) $ (36)
===================================== ======= ======== ========
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
---------------------------
2000 1999
- ------------------------------------ ------------- -------------
(in millions)
Balance at beginning of year $438 $464
Service cost 7 8
Interest cost 36 30
Benefits paid (21) (19)
Actuarial gain and
employee transfers (28) (45)
Amendments 63 -
- ------------------------------------ ------------- -------------
Balance at end of year $495 $438
==================================== ============= =============
23
NOTES (continued)
Georgia Power Company 2000 Annual Report
Plan Assets
---------------------------
2000 1999
- ------------------------------------ ------------- -------------
(in millions)
Balance at beginning of year $177 $150
Actual return on plan assets 12 11
Employer contributions 30 35
Benefits paid (21) (19)
- ------------------------------------ ------------- -------------
Balance at end of year $198 $177
==================================== ============= =============
The accrued postretirement costs recognized in the Balance Sheets were as
follows:
2000 1999
- ------------------------------------------ --------- ----------
(in millions)
Funded status $ (297) $ (261)
Unrecognized transition obligation 113 122
Unrecognized prior service cost 60 -
Unrecognized gain (13) -
Unrecognized net actuarial loss - 10
Fourth quarter contributions 27 14
- ------------------------------------------ --------- ----------
Accrued liability recognized in the
Balance Sheets $ (110) $(115)
========================================== ========= ==========
Components of the plans' net periodic cost were as follows:
2000 1999 1998
- ------------------------------------- ------- -------- --------
(in millions)
Service cost $ 7 $ 8 $ 7
Interest cost 36 30 32
Expected return on plan assets (16) (10) (9)
Recognized net actuarial loss - 1 1
Net amortization 12 9 9
- ------------------------------------- ------- -------- --------
Net postretirement cost $ 39 $ 38 $40
===================================== ======= ======== ========
An additional assumption used in measuring the accumulated postretirement
benefit obligations was a weighted average medical care cost trend rate of 7.29
percent for 2000, decreasing gradually to 5.50 percent through the year 2005,
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,
2000 as follows:
1 Percent 1 Percent
Increase Decrease
- ----------------------------------- ------------- -------------
(in millions)
Benefit obligation $ 39 $ 34
Service and interest costs 3 3
=================================== ============= =============
Employee Savings Plan
The Company also 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 2000, 1999, and 1998 were $15
million, $15 million, and $14 million, respectively.
3. CONTINGENCIES & REGULATORY MATTERS
Retail Rate Order
On December 18, 1998, the GPSC approved a three-year retail rate order for the
Company ending December 31, 2001. Under the terms of the order, earnings are
evaluated against a retail return on common equity range of 10 percent to 12.5
percent. Retail rates were decreased by $262 million on an annual basis
effective January 1, 1999, and by an additional $24 million effective January 1,
2000. The order further provides 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 will
be applied to rate reductions, with the remaining one-third retained by the
Company. Pursuant to the order, in 2000 and 1999, the Company recorded $85
million each year in accelerated amortization of regulatory assets. In 2000, the
Company also recorded the additional $50 million of accelerated amortization.
The accelerated amortization is recorded in a regulatory liability account and,
as mandated by the GPSC, the Company recorded $10 million of interest on the
amounts in the regulatory liability account. In addition, the Company recorded
$44 million and $79 million of revenue subject to refund for estimated earnings
above 12.5 percent retail return on common equity in 2000 and 1999,
respectively. Refunds applicable to 1999 were made to customers in 2000. The
estimated 2000 refund is included in other current liabilities on the Balance
Sheet. The Company will file a general rate case on July 2, 2001, in response to
24
NOTES (continued)
Georgia Power Company 2000 Annual Report
which the GPSC would be expected to determine whether the rate order should be
continued, modified, or discontinued.
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 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.
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 unless such costs can be recovered
through regulated rates.
Other Environmental Contingencies
In January 1995, the Company and four other unrelated entities were notified by
the EPA that they have been designated as potentially responsible parties under
the Comprehensive Environmental Response, Compensation and Liability Act with
respect to a site in Brunswick, Georgia. As of December 31, 2000, the Company
has recognized approximately $5 million in cumulative expenses associated with
the Company's agreed upon share of removal and remedial investigation and
feasibility study costs for this site. The final outcome of this matter cannot
now be determined. However, based on the nature and extent of the Company's
activities relating to the site, management believes that the Company's portion
of any remaining remediation costs should not be material to the financial
statements.
In compliance with the Georgia Hazardous Site Response Act of 1993, the
State of Georgia was required to compile an inventory of all known or suspected
sites where hazardous wastes, constituents, or substances have been disposed of
or released in quantities deemed reportable by the State. In developing this
list, the State identified several hundred properties throughout the State,
including 34 sites which may require environmental remediation that were either
previously or are currently owned by the Company. The majority of these sites
are electrical power substations and power generation facilities. The Company
has remediated ten electrical substations on the list at a cumulative cost of
approximately $3 million through December 31, 2000. The State has removed from
the list three power generation facilities following the assessment which
indicated no remediation was necessary. In addition, the Company has recognized
approximately $27.5 million in cumulative expenses through December 31, 2000 for
the assessment of the remaining sites on the list and the anticipated clean-up
cost for 14 sites that the Company plans to remediate. Any additional costs of
remediating the remaining sites cannot presently be determined until such
studies are completed for each site and the State determines whether remediation
is required. If all listed sites were required to be remediated, the Company
could incur expenses of up to approximately $5 million in additional clean-up
costs and construction expenditures of up to approximately $37 million to
develop new waste management facilities or install additional pollution control
devices.
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
25
NOTES (continued)
Georgia Power Company 2000 Annual Report
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.
In January 1997, the GPSC approved a performance award of approximately
$11.7 million for performance during the 1993-1995 period. This award was
collected through the retail fuel cost recovery provision and recognized in
income over the 36-month period ending in December 1999. In February 2000, the
GPSC approved a performance award of approximately $7.8 million for performance
during the 1996-1998 period. This award is being collected through the retail
fuel cost recovery provision and recognized in income over a 36-month period
that began in January 2000, 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 and a new defendant, Southern Company Energy Solutions, Inc. The
lawsuit is in the discovery stage. The final outcome of this case cannot now be
determined.
4. COMMITMENTS
Construction Program
The Company is constructing Plant Dahlberg, a ten unit, 800 megawatt combustion
turbine peaking power plant. Units one through eight began operation in May
2000; units nine and ten are expected to begin operation in June 2001. The
Company is also constructing a 571 megawatt combined cycle unit and a 610
megawatt combined cycle unit at Plant Goat Rock that will begin operation in
2002 and in 2003, respectively, and an addition of two 566 megawatt combined
cycle units at Plant Wansley, to begin operation in 2002. During 2001, the
Company plans to transfer the units at Plants Dahlberg, Goat Rock, and Wansley
at net book value to Southern Power Company (SPC), a new subsidiary formed by
Southern Company. Significant construction of transmission and distribution
facilities, and projects to upgrade and extend the useful life of generating
plants and to remain in compliance with environmental requirements will
continue. The Company currently estimates property additions to be approximately
$1.6 billion in 2001, $1.3 billion in 2002, and $0.8 billion in 2003. If the
Company transfers wholesale generation assets to SPC in 2001 as contemplated,
construction expenditures for the years 2001 through 2003 will total $1.0
billion, $0.9 billion, and $0.7 billion, respectively.
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.
Total estimated long-term fossil and nuclear fuel commitments at December 31,
2000 were as follows:
Minimum
Year Obligations
- ----
----------------------
(in millions)
2001 $ 1,006
2002 625
2003 586
2004 430
2005 342
2006 and beyond 873
- ----------------------------------------- ----------------------
Total minimum obligations $ 3,862
========================================= ======================
Additional commitments for coal and for nuclear fuel will be required in
the future to supply the Company's fuel needs.
Purchased Power Commitments
The Company and an affiliate, Alabama Power Company, own equally all of the
outstanding capital stock of Southern Electric Generating Company (SEGCO), which
26
NOTES (continued)
Georgia Power Company 2000 Annual Report
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 Company 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:
2000 1999 1998
----------- ---------- ----------
(in millions)
Energy $57 $51 $45
Capacity 30 29 30
- ---------------------------- ----------- ---------- ----------
Total $87 $80 $75
============================ =========== ========== ==========
Kilowatt-hours 3,835 3,338 3,146
- ---------------------------- ----------- ---------- ----------
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 $58 million, $57 million, and $56 million in 2000, 1999, and 1998,
respectively. The current projected Plant Vogtle capacity payments are:
Year Capacity Payments
----------------------
(in millions)
2001 $ 59
2002 58
2003 58
2004 55
2005 55
2006 and beyond 539
- ----------------------------------------- ----------------------
Total capacity payments $ 824
========================================= ======================
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.
The Company has entered into other various long-term commitments for the
purchase of electricity. Estimated total long-term obligations at December 31,
2000 were as follows:
Year Other Obligations
----------------------
(in millions)
2001 $ 22
2002 39
2003 41
2004 40
2005 40
2006 and beyond 154
- ----------------------------------------- ----------------------
Total other obligations $336
========================================= ======================
Operating Leases
The Company has entered into coal rail car rental agreements with various terms
and expiration dates. These expenses totaled $16 million for 2000, $11 million
for 1999, and $13 million for 1998. At December 31, 2000, estimated minimum
rental commitments for these noncancelable operating leases were as follows:
Year Minimum Obligations
--------------------------
(in millions)
2001 $ 15
2002 15
2003 15
2004 16
2005 14
2006 and beyond 102
- -------------------------------------- --------------------------
Total minimum obligations $ 177
====================================== ==========================
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
private insurance, with the remaining coverage provided by a mandatory program
27
NOTES (continued)
Georgia Power Company 2000 Annual Report
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 be insured against increased costs of replacement power in an
amount up to $3.5 million per week -- starting 12 weeks after the outage -- for
one year and up to $2.8 million per week for the second and third 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 $19 million.
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, 2000, 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% $3,301* $1,724
Plant Hatch (nuclear) 50.1 873 650
Plant Wansley (coal) 53.5 300 150
Plant Scherer (coal)
Units 1 and 2 8.4 112 53
Unit 3 75.0 545 207
Plant McIntosh
Common Facilities 75.0 19 2
(combustion-turbine)
Rocky Mountain 25.4 169* 72
(pumped storage)
Intercession City 33.3 11 1
(combustion-turbine)
- ---------------------------- ----------- ------------- -------------
* Investment net of write-offs.
7. LONG-TERM POWER SALES AND LEASE AGREEMENTS
The Company and the other integrated Southeast utilities of Southern Company
have long-term contractual agreements for the sale of capacity and energy to
non-affiliated utilities located outside the system's service area. These
28
NOTES (continued)
Georgia Power Company 2000 Annual Report
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)
2000 $ 30 124
1999 32 162
1998 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 2000 with a minimum of three years notice until the expiration of
the contracts in 2010.
During 2000, the Company entered into certain operating leases for portions
of its generating unit capacity. Minimum future capacity revenues from
noncancelable operating leases as of December 31, 2000 were as follows:
Year Minimum Obligations
--------------------------
(in millions)
2001 $ 41
2002 45
2003 45
2004 45
2005 5
2006 and beyond -
- -------------------------------------- --------------------------
Total minimum obligations $181
====================================== ==========================
8. INCOME TAXES
At December 31, 2000, tax-related regulatory assets were $566 million and
tax-related regulatory liabilities were $247 million. The assets are
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:
2000 1999 1998
---------- --------- ----------
Total provision for income taxes: (in millions)
Federal:
Current $ 342 $333 $415
Deferred (34) (34) (87)
Deferred investment tax
credits - - 7
- --------------------------------- ---------- --------- ----------
308 299 335
- --------------------------------- ---------- --------- ----------
State:
Current 48 54 77
Deferred (5) (6) (13)
Deferred investment tax
credits 10 5 -
- --------------------------------- ---------- --------- ----------
Total $361 $352 $399
================================= ========== ========= ==========
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:
2000 1999
--------- --------------
(in millions)
Deferred tax liabilities:
Accelerated depreciation $ 1,755 $1,766
Property basis differences 683 729
Other 243 155
- --------------------------------------------- --------- --------------
Total 2,681 2,650
- --------------------------------------------- --------- --------------
Deferred tax assets:
Other property basis differences 189 200
Federal effect of state deferred taxes 91 93
Other deferred costs 208 109
Other 37 48
- --------------------------------------------- --------- --------------
Total 525 450
- --------------------------------------------- --------- --------------
Net deferred tax liabilities 2,156 2,200
Portion included in current assets 27 3
- --------------------------------------------- --------- --------------
Accumulated deferred income taxes
in the Balance Sheets $ 2,183 $2,203
============================================= ========= ==============
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 2000 and 1999, and $22 million in 1998. At December
31, 2000, all investment tax credits available to reduce federal income taxes
payable had been utilized.
29
NOTES (continued)
Georgia Power Company 2000 Annual Report
A reconciliation of the federal statutory tax rate to the effective income
tax rate is as follows:
2000 1999 1998
-------- -------- --------
Federal statutory rate 35% 35% 35%
State income tax, net of
federal deduction 4 4 4
Non-deductible book
depreciation 2 2 6
Other (2) (2) (4)
- ------------------------------------ -------- -------- --------
Effective income tax rate 39% 39% 41%
==================================== ======== ======== ========
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.
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. At December 31, 2000,
$891 million 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. If additional first mortgage bonds are issued, supplemental
indentures in connection with those issues may contain more stringent
restrictions than those currently in effect. 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
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 $378.8 million of its
first mortgage bonds outstanding at December 31, 2000, which are pledged as
security for its obligations under pollution control revenue contracts. No
interest on these first mortgage bonds is payable unless and until a default
occurs on the installment purchase or loan agreements.
Senior Notes
In February 2000 and February 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, including its first mortgage bonds.
Bank Credit Arrangements
At the beginning of 2001, the Company had unused credit arrangements with banks
totaling $1.8 billion, of which $1.3 billion expires at various times during
2001, 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 20, 2001, 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.
30
NOTES (continued)
Georgia Power Company 2000 Annual Report
Approximately $115 million of the $1.3 billion arrangements expiring during
2001 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, 2000 was $979 million.
In addition, the Company borrows under uncommitted lines of credit with
banks and through a $750 million commercial paper program that has the liquidity
support of committed bank credit arrangements. Average compensating balances
held under these committed facilities were not material in 2000.
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, 2000 and 1999, the Company had a capitalized
lease obligation for its corporate headquarters building of $87 million with an
interest rate of 8.1 percent. The lease agreement provides for payments that are
minimal in early years and escalate through the first 21 years of the lease. 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 is
being deferred as a cost to be recovered in the future as ordered by the GPSC.
At December 31, 2000 and 1999, the interest and lease amortization deferred on
the Balance Sheets are $55 million and $54 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.
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:
2000 1999
--------- --------
(in millions)
Bond improvement fund requirements $ - $ 5
Capital lease - current portion 2 1
First mortgage bond maturities
and redemptions - 100
Pollution control bond maturities
and redemptions - 50
- -------------------------------------------- --------- --------
Total long-term debt $2 $156
============================================ ========= ========
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.
Redemption of Securities
The Company plans to continue, to the extent possible, a program of redeeming or
replacing debt and preferred securities in cases where opportunities exist to
reduce financing costs. Issues may be repurchased in the open market or called
at premiums as specified under terms of the issue. They may also be redeemed at
face value to meet improvement fund requirements, to meet replacement provisions
of the mortgage, or through use of proceeds from the sale of property pledged
under the mortgage.
31
10. QUARTERLY FINANCIAL DATA (UNAUDITED)
Summarized quarterly financial information for 2000 and 1999 is as follows:
Net Income
After
Operating Operating Dividends on
Quarter Ended Revenues Income Preferred Stock
- ------------------------ ------------ -------------- ----------------
(in millions)
--------------------------------------------
March 2000 $ 992 $223 $ 94
June 2000 1,221 311 148
September 2000 1,545 537 283
December 2000 1,113 162 34
March 1999 $ 931 $224 $ 92
June 1999 1,092 299 138
September 1999 1,466 557 296
December 1999 968 115 15
- ------------------------ ------------ -------------- ----------------
Under the GPSC retail rate order, the Company recorded $135 million and $85
million of accelerated amortization in 2000 and 1999, respectively, which were
recorded monthly as an operating expense. The fourth quarter December 1999
operating income has been restated to reflect the accelerated amortization as an
operating expense rather than as amortization of premium on reacquired debt. See
Note 3 to the financial statements under "Retail Rate Order" for additional
information.
The Company's business is influenced by seasonal weather conditions.
32
SELECTED FINANCIAL AND OPERATING DATA 1996-2000
Georgia Power Company 2000 Annual Report
- --------------------------------------------------------------------------------------------------------------------------------
2000 1999 1998 1997 1996
- --------------------------------------------------------------------------------------------------------------------------------
Operating Revenues (in thousands) $4,870,618 $4,456,675 $4,738,253 $4,385,717 $4,416,779
Net Income after Dividends
on Preferred Stock (in thousands) $559,420 $541,383 $570,228 $593,996 $580,327
Cash Dividends
on Common Stock (in thousands) $549,600 $543,000 $536,600 $520,000 $475,500
Return on Average Common Equity (percent) 13.66 14.02 14.61 14.53 13.73
Total Assets (in thousands) $13,133,609 $12,361,860 $12,033,618 $12,573,728 $13,006,635
Gross Property Additions (in thousands) $1,078,163 $790,464 $499,053 $475,921 $428,220
- --------------------------------------------------------------------------------------------------------------------------------
Capitalization (in thousands):
Common stockholder's equity $4,249,544 $3,938,210 $3,784,172 $4,019,728 $4,154,281
Preferred stock 14,569 14,952 15,527 157,247 464,611
Company obligated mandatorily
redeemable preferred securities 789,250 789,250 689,250 689,250 325,000
Long-term debt 3,041,939 2,688,358 2,744,362 2,982,835 3,200,419
- --------------------------------------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) $8,095,302 $7,430,770 $7,233,311 $7,849,060 $8,144,311
================================================================================================================================
Capitalization Ratios (percent):
Common stockholder's equity 52.5 53.0 52.3 51.2 51.0
Preferred stock 0.2 0.2 0.2 2.0 5.7
Company obligated mandatorily
redeemable preferred securities 9.7 10.6 9.5 8.8 4.0
Long-term debt 37.6 36.2 38.0 38.0 39.3
- --------------------------------------------------------------------------------------------------------------------------------
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 a2 a2 a2 a2 a2
Standard and Poor's BBB+ A- 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 1,669,566 1,632,450 1,596,488 1,561,675 1,531,453
Commercial 237,977 229,524 221,180 211,672 205,087
Industrial 8,533 8,958 9,485 9,988 10,424
Other 3,159 3,060 3,034 2,748 2,645
- --------------------------------------------------------------------------------------------------------------------------------
Total 1,919,235 1,873,992 1,830,187 1,786,083 1,749,609
================================================================================================================================
Employees (year-end): 8,855 8,961 8,371 8,354 10,346
- --------------------------------------------------------------------------------------------------------------------------------
33
SELECTED FINANCIAL AND OPERATING DATA 1996-2000 (continued)
Georgia Power Company 2000 Annual Report
- ------------------------------------------------------------------------------------------------------------------------------
2000 1999 1998 1997 1996
- ------------------------------------------------------------------------------------------------------------------------------
Operating Revenues (in thousands):
Residential $ 1,535,684 $1,410,099 $ 1,486,699 $ 1,326,787 $ 1,371,033
Commercial 1,620,466 1,527,880 1,591,363 1,493,353 1,486,586
Industrial 1,154,789 1,143,001 1,170,881 1,110,311 1,118,633
Other 6,399 (30,892) 49,274 47,848 47,060
- ------------------------------------------------------------------------------------------------------------------------------
Total retail 4,317,338 4,050,088 4,298,217 3,978,299 4,023,312
Sales for resale - non-affiliates 297,643 210,104 259,234 282,365 281,580
Sales for resale - affiliates 96,150 76,426 81,606 38,708 35,886
- ------------------------------------------------------------------------------------------------------------------------------
Total revenues from sales of electricity 4,711,131 4,336,618 4,639,057 4,299,372 4,340,778
Other revenues 159,487 120,057 99,196 86,345 76,001
- ------------------------------------------------------------------------------------------------------------------------------
Total $4,870,618 $4,456,675 $4,738,253 $4,385,717 $4,416,779
==============================================================================================================================
Kilowatt-Hour Sales (in thousands):
Residential 20,693,481 19,404,709 19,481,486 17,295,022 17,826,451
Commercial 25,628,402 23,715,485 22,861,391 21,134,346 20,823,073
Industrial 27,543,265 27,300,355 27,283,147 26,701,685 26,191,831
Other 568,906 551,451 543,462 538,163 536,057
- ------------------------------------------------------------------------------------------------------------------------------
Total retail 74,434,054 70,972,000 70,169,486 65,669,216 65,377,412
Sales for resale - non-affiliates 6,463,723 5,060,931 6,438,891 6,795,300 7,868,342
Sales for resale - affiliates 2,435,106 1,795,243 2,038,400 1,706,699 1,180,207
- ------------------------------------------------------------------------------------------------------------------------------
Total 83,332,883 77,828,174 78,646,777 74,171,215 74,425,961
==============================================================================================================================
Average Revenue Per Kilowatt-Hour (cents):
Residential 7.42 7.27 7.63 7.67 7.69
Commercial 6.32 6.44 6.96 7.07 7.14
Industrial 4.19 4.19 4.29 4.16 4.27
Total retail 5.80 5.71 6.13 6.06 6.15
Sales for resale 4.43 4.18 4.02 3.78 3.51
Total sales 5.65 5.57 5.90 5.80 5.83
Residential Average Annual
Kilowatt-Hour Use Per Customer 12,520 12,006 12,314 11,171 11,763
Residential Average Annual
Revenue Per Customer $929.11 $872.47 $939.73 $857.01 $904.70
Plant Nameplate Capacity
Ratings (year-end) (megawatts) 15,114 14,474 14,437 14,437 14,367
Maximum Peak-Hour Demand (megawatts):
Winter 12,014 11,568 11,959 10,407 10,410
Summer 14,930 14,575 13,923 13,153 12,914
Annual Load Factor (percent) 61.6 58.9 58.7 57.4 62.2
Plant Availability (percent):
Fossil-steam 86.1 84.3 86.0 85.8 85.2
Nuclear 91.5 89.3 91.6 88.8 89.3
- ------------------------------------------------------------------------------------------------------------------------------
Source of Energy Supply (percent):
Coal 62.3 63.0 62.3 64.3 60.4
Nuclear 17.4 18.0 18.3 18.8 18.2
Hydro 0.7 0.9 2.2 2.2 2.2
Oil and gas 1.8 1.6 2.2 0.6 0.5
Purchased power -
From non-affiliates 8.1 6.6 6.5 2.7 5.6
From affiliates 9.7 9.9 8.5 11.4 13.1
- ------------------------------------------------------------------------------------------------------------------------------
Total 100.0 100.0 100.0 100.0 100.0
==============================================================================================================================
34