SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
FORM 8-K
CURRENT REPORT
Pursuant to Section 13 or 15(d) of the
Securities Exchange Act of 1934
Date of Report (Date of earliest event reported) February 16, 2000
-----------------------------
GEORGIA POWER COMPANY
- -------------------------------------------------------------------------------
(Exact name of registrant as specified in its charter)
Georgia 1-6468 58-0257110
- -------------------------------------------------------------------------------
(State or other jurisdiction (Commission (IRS Employer
of incorporation) File Number) Identification No.)
241 Ralph McGill Blvd, NE, Atlanta, Georgia 30308
- -------------------------------------------------------------------------------
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code (404) 506-6526
--------------------------
N/A
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(Former name or former address, if changed since last report.)
<PAGE>
Item 7. Financial Statements and Exhibits.
(c) Exhibits.
23 - Consent of Arthur Andersen LLP.
27 - Financial Data Schedule.
99 - Audited Financial Statements of Georgia Power
Company as of December 31, 1999.
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934,
the registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
GEORGIA POWER COMPANY
By /s/Wayne Boston
Wayne Boston
Assistant Secretary
Date: March 2, 2000
Exhibit 23
Arthur Andersen LLP
Suite 2500
133 Peachtree Street, NE
Atlanta, GA 30303-1816
404-658-1776
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the incorporation
of our report dated February 16, 2000 on the financial statements of Georgia
Power Company, included in this Form 8-K, into Georgia Power Company's
previously filed Registration Statement File Nos. 333-43895 and 333-75193.
/s/Arthur Andersen LLP
Atlanta, Georgia
February 28, 2000
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<LEGEND>
This schedule contains summary financial information extracted from the
financial statements filed as Exhibit 99 and is qualified in its entirety by
reference to such financial statements.
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<CIK> 0000041091
<NAME> GEORGIA POWER COMPANY
<MULTIPLIER> 1,000
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<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> Dec-31-1999
<PERIOD-END> Dec-31-1999
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 9,805,313
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<TOTAL-CURRENT-ASSETS> 1,028,553
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<TOTAL-ASSETS> 12,276,860
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<CAPITAL-SURPLUS-PAID-IN> 1,816,023
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789,250
14,952
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<SHORT-TERM-NOTES> 171,461
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</TABLE>
MANAGEMENT'S REPORT
Georgia Power Company 1999 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 generally accepted accounting
principles appropriate in the circumstances, 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 books and 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
directors who are not employees, 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 generally accepted accounting
principles.
/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
February 16, 2000
1
<PAGE>
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, 1999 and 1998, and the related statements
of income, common stockholders' equity, and cash flows for each of the three
years in the period ended December 31, 1999. 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 11-30) referred to above
present fairly, in all material respects, the financial position of Georgia
Power Company as of December 31, 1999 and 1998, and the results of its
operations and its cash flows for each of the three years in the period ended
December 31, 1999, in conformity with accounting principles generally accepted
in the United States.
/s/Arthur Andersen LLP
Atlanta, Georgia
February 16, 2000
2
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL
CONDITION
Georgia Power Company 1999 Annual Report
RESULTS OF OPERATIONS
Earnings
Georgia Power Company's 1999 earnings totaled $541 million, representing a $29
million (5.1 percent) decrease from 1998. This earnings decrease is 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 from normal
operations increased due primarily to lower accelerated depreciation under the
1998 Georgia Public Service Commission (GPSC) rate order, sales growth and
decreased financing costs, partially offset by retail rate reductions under the
new order and lower wholesale revenues. Earnings for 1998 totaled $570 million,
representing a $24 million (4.0 percent) decrease from 1997. This earnings
decrease resulted primarily from higher operating expenses, accelerated
depreciation charges pursuant to a previous GPSC retail accounting order ending
December 1998, lower wholesale revenues, and the write-off of a portion of the
Rocky Mountain plant investment. These decreases to earnings were partially
offset by higher retail revenues, lower financing costs and the effect of the
IRS settlement.
Revenues
The following table summarizes the factors impacting operating revenues for the
1997-1999 period:
Increase (Decrease)
From Prior Year
--------------------------------
1999 1998 1997
--------------------------------
Retail - (in millions)
1998 GPSC rate order $(262) $ - $ -
Revenue subject to refund (79) - -
Sales growth 102 174 62
Weather (53) 101 (74)
Fuel cost recovery and other 44 45 (33)
- --------------------------------------------------------------------
Total retail (248) 320 (45)
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Sales for resale -
Non-affiliates (49) (23) 1
Affiliates (5) 43 3
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Total sales for resale (54) 20 4
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Other operating revenues 21 13 10
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Total operating revenues $(281) $ 353 $ (31)
====================================================================
Percent change (5.9)% 8.0% (0.7)%
- --------------------------------------------------------------------
Retail revenues of $4.1 billion in 1999 decreased $248 million (5.8 percent)
primarily due to retail rate reductions under the 1998 GPSC rate order. Pursuant
to the 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. Refunds will be made to customers in 2000. See Note 3 to the financial
statements under "Retail Rate Orders" for additional information. Retail
revenues of $4.3 billion in 1998 increased $320 million (8.0 percent) from 1997
primarily due to higher energy sales to residential and commercial customers.
Fuel revenues generally represent the direct recovery of fuel expense,
including the fuel component of purchased energy, and do not affect net income.
Wholesale revenues from sales to non-affiliated utilities decreased in 1999
and 1998 and were as follows:
1999 1998 1997
-------------------------------
(in millions)
Outside service area -
Long-term contracts $ 55 $ 51 $ 71
Other sales 74 93 79
Inside service area 81 115 132
- ---------------------------------------------------------------
Total $ 210 $ 259 $ 282
===============================================================
Revenues from long-term contracts outside the service area increased
slightly in 1999 due to increased energy sales and decreased in 1998 primarily
due to lower capacity charges and decreased energy sales. See Note 7 to the
financial statements for further information regarding these sales. Revenues
from other sales outside the service area decreased in 1999 and increased in
1998 primarily due to the effect of power marketing activities and were
generally offset by a corresponding decrease and increase, respectively, in
purchased power from non-affiliates. Wholesale revenues from customers within
the service area decreased in 1999 and 1998 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.
3
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 1999 Annual Report
Other operating revenues increased $21 million (21 percent) primarily due to
increased revenues from equipment rentals. In 1998, other operating revenues
increased $13 million (14.9 percent) primarily due to increased revenues from
the transmission of electricity.
Kilowatt-hour (KWH) sales for 1999 and the percent change by year were as
follows:
Percent Change
----------------------------
1999
KWH 1999 1998 1997
--------- -----------------------------
(in billions)
Residential 19.4 (0.4)% 12.6% (3.0)%
Commercial 23.7 3.7 8.2 1.5
Industrial 27.3 0.1 2.2 1.9
Other 0.6 1.5 1.0 0.4
--------
Total retail 71.0 1.1 6.9 0.4
--------
Sales for resale -
Non-affiliates 5.0 (21.4) (5.2) (13.6)
Affiliates 1.8 (11.9) 19.4 44.6
--------
Total sales for resale 6.8 (19.1) (0.3) (6.0)
--------
Total sales 77.8 (1.0) 6.0 (0.3)
========
- ------------------------------------------------------------------
Residential sales decreased 0.4 percent in 1999 due to moderate summer
temperatures, while commercial sales increased 3.7 percent due to strong
regional economic growth. Industrial sales remained fairly constant. Residential
and commercial sales increased in 1998 12.6 percent and 8.2 percent,
respectively, and industrial sales increased slightly by 2.2 percent. The
increases are attributed primarily to sales growth and hotter temperatures in
the summer months.
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:
1999 1998 1997
-------------------------
Total generation
(billions of KWH) 69.3 69.1 66.5
Sources of generation
(percent) --
Coal 75.5 73.3 74.8
Nuclear 21.6 21.6 21.8
Hydro 1.0 2.6 2.7
Oil and gas 1.9 2.5 0.7
Average cost of fuel per net
KWH generated
(cents) -- 1.34 1.36 1.32
- ---------------------------------------------------------------
Fuel expense increased 0.3 percent in 1999 due to a slight increase in
generation, partially offset by a lower average cost of fuel. Fuel expense
increased 7.0 percent in 1998 primarily due to an increase in generation to meet
higher energy demands and a higher average cost of fuel.
Purchased power expense decreased slightly in 1999. Purchased power expense
in 1998 increased $70 million (21.9 percent) over the prior year primarily due
to higher energy demands and power marketing activities. As discussed earlier,
the expense associated with energy purchased for power marketing activities is
generally offset by revenue when resold to non-affiliates.
Other operation and 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. Other operation and maintenance expenses increased 15.5
percent in 1998 primarily due to expenses related to the customer service system
discussed above, modification of certain information systems for year 2000
compliance discussed below, an increase in outage costs at generating
facilities, and increased line maintenance.
4
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 1999 Annual Report
Depreciation and amortization decreased $346 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. Depreciation and amortization increased $121 million in 1998
primarily due to accelerated depreciation of generating plant pursuant to the
previous retail accounting order and an increase in plant-in-service. See Note 3
to the financial statements under "Retail Rate Orders" for additional
information.
As a result of the 1998 retail rate order, the Company recorded a $34
million pre-tax write-off associated with a portion of its investment in the
Rocky Mountain plant in 1998. See Note 3 to the financial statements under
"Rocky Mountain Status" for additional information.
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 1999 due primarily to
increased bad debt expense related to consumer energy efficiency improvement
financing.
Financing costs decreased in 1999 and 1998. These changes were primarily due
to the refinancing or retirement of securities. The Company refinanced or
retired $775 million and $754 million of securities in 1999 and 1998,
respectively. Dividends on preferred stock decreased $4 million and $13 million
in 1999 and 1998, respectively. Pursuant to the new three-year retail rate order
which the Company began operating under on January 1, 1999, the Company recorded
$85 million in accelerated amortization of premium on reacquired debt. Other
interest charges decreased $12 million in 1999 primarily due to the recognition
in 1998 of interest related to tax issues. Distributions on preferred securities
of subsidiary companies increased $11 million and $7 million in 1999 and 1998,
respectively, primarily due to the issuance of additional mandatorily redeemable
preferred securities in 1999 and 1997.
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 will continue to be evaluated against
a retail return on common equity range of 10 percent to 12.5 percent, with rate
reductions of $262 million in 1999 and an additional reduction of $24 million 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 order, in 1999 the Company recorded $85 million in accelerated amortization
of premium on reacquired debt. The Company also recorded $79 million of revenue
subject to refund for estimated earnings above 12.5 percent. Refunds will be
made to customers in 2000. The Company will not file for a general base rate
increase unless its projected retail return on common equity falls below 10
percent, and will be required to file a general rate case on July 1, 2001 in
response to which the GPSC would be expected to determine whether the rate order
should be continued, modified, or discontinued. See Note 3 to the financial
statements under "Retail Rate Orders" for additional information.
5
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 1999 Annual Report
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 1999 is projected to be approximately 2.9 percent
annually on average during 2000 through 2002.
The Company has entered into two purchase power agreements scheduled to
begin after 1999. The first agreement is for five years and will begin in June
2000. The agreement is for approximately 215 megawatts, and capacity payments
are estimated to be between $7 million and $8 million each year. The second
agreement is for seven years and will begin in June 2002. The agreement is for
approximately 310 megawatts during the first three years and approximately 465
megawatts during the remaining four years. Capacity payments are estimated to be
between $16 million and $17 million in each of the first three years and then
between $23 million and $24 million in each of the last four years of the
contract.
The Company is constructing a ten unit, 800 megawatt combustion turbine
peaking power plant that will serve the wholesale market. Units one through
eight will begin operation in 2000; units nine and ten will begin operation in
2001. The Company also plans to construct a 570 megawatt combined cycle unit
that will begin operation in 2002 and will also serve the wholesale market. The
Company has entered into wholesale contracts to sell 560 megawatts of the new
capacity. The Company is also planning to construct two 568 megawatt combined
cycle units at Plant Wansley, to begin operation in 2002. The Company has
applied to the GPSC for certification of these units to serve retail customers.
Savannah Electric (also a wholly-owned subsidiary of Southern Company) will
purchase 200 megawatts of capacity from these units. See Note 4 to the financial
statements under "Construction Program" for additional information.
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 currently undergoing a
period of dramatic change 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. The Company is aggressively working to maintain and expand its
share of wholesale sales in the Southeastern power markets. Although the Energy
Act 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
encourages utilities owning transmission systems to form RTOs on a voluntary
basis. To facilitate the development of RTOs, the FERC will convene regional
conferences for utilities, customers, and other members of the public to discuss
formation of RTOs. In addition to participating in the regional conferences,
utilities owning transmission systems, including the Company, are required to
make a filing by October 15, 2000. The filing must contain either a proposal for
RTO participation or a description of the efforts made to participate in an RTO,
the reasons for non-participation, any obstacles to participation, and any plans
for further work toward participation. The RTOs that are proposed in the filings
should be operational by December 15, 2001. The Company is evaluating the issue
and the outcome 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
6
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 1999 Annual Report
transmission pricing and recovery of costs. The GPSC plans to release a report
on an initial assessment of the range of potential stranded costs in 2000. 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 and other costs through the three-year retail rate
order. See Note 3 to the financial statements under "Retail Rate Orders" for
additional information.
Unless the Company remains a low-cost producer and provides quality service,
the Company's retail energy sales growth could be limited as competition
increases. Conversely, continuing to be a low-cost producer could provide
opportunities to increase market share and profitability in markets that evolve
with changing regulation.
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. 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 has questioned certain
of the current accounting practices of the electric utility industry - including
the Company's - regarding the recognition, measurement, and classification of
decommissioning costs for nuclear generating facilities in the financial
statements. In response to these questions, the FASB has decided to review 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.
Year 2000 Challenge
The work undertaken by the Company to prepare critical computer systems and
other date sensitive devices to function correctly in the Year 2000 was
successful. There were no material incidents reported and no disruption of
electric service within the service area. There were no reports of significant
events regarding third parties that impacted revenues or expenses.
For the Company, original projected total costs for Year 2000 readiness,
including the Company's share of costs of Southern Nuclear Operating Company,
were approximately $38 million. These costs include labor necessary to identify,
test, and renovate affected devices and systems, and costs for reporting
requirements to state and federal agencies. From its inception through December
31, 1999, the Year 2000 program costs, recognized as expense, amounted to $41
million. An additional $2 million is projected to be spent in 2000.
Exposure to Market Risks
Due to cost-based rate regulation, the Company currently has limited exposure to
market volatility in interest rates 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, 1999, 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, 1999, a near-term 100 basis point change in interest
rates would not materially affect the financial statements.
New Accounting Standard
The FASB has issued Statement No. 133, Accounting for Derivative Instruments and
Hedging Activities, which must be adopted by January 2001. This statement
establishes accounting and reporting standards for derivative instruments -
including certain derivative instruments embedded in other contracts - and for
7
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 1999 Annual Report
hedging activities. The Company has not yet quantified the impact of adopting
this statement on its financial statements; however, the adoption could increase
volatility in earnings.
FINANCIAL CONDITION
Plant Additions
In 1999 gross utility plant additions were $790 million. 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 or long-term debt, and from equity from
Southern. The Statements of Cash Flows provide additional details.
Financing Activities
In 1999 the Company continued to lower its financing costs by refinancing
higher-cost issues. New issues during 1997 through 1999 totaled $1.8 billion and
retirement or repayment of securities totaled $2.2 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 1997 through 1999, as of year-end, were as follows:
1999 1998 1997
----------------------------------
Composite interest rate
on long-term debt 5.48% 5.64% 6.11%
Composite preferred
stock dividend rate 4.60 5.52 5.18
Composite preferred
securities dividend rate 7.49 7.89 7.89
- ------------------------------------------------------------------
Liquidity and Capital Requirements
Cash provided from operations decreased by $206 million in 1999, primarily due
to lower retail revenues.
The Company estimates that construction expenditures for the years 2000
through 2002 will total $1.2 billion, $1.5 billion and $1.5 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 improvement fund requirements, redemptions announced,
and maturities of long-term debt are expected to total $168 million during 2000
through 2002.
As a result of requirements by the Nuclear Regulatory Commission, the
Company has established external trust funds for the purpose of funding nuclear
decommissioning costs. The amount to be funded is $30 million each year in 2000,
2001 and 2002. 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 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 $1.3 billion of unused credit arrangements with banks at the
beginning of 2000. See Note 9 to the financial statements under "Bank Credit
Arrangements" for additional information.
The Company historically has relied on issuances of first mortgage bonds and
preferred stock, in addition to pollution control revenue bonds issued for its
benefit by public authorities, to meet its long-term external financing
requirements. Recently, the Company's financings have also consisted of
unsecured debt and trust preferred securities. In this regard, the Company
8
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 1999 Annual Report
sought and obtained stockholder approval in 1997 to amend its corporate charter
eliminating restrictions on the amounts of unsecured indebtedness it may incur.
If the Company chooses to issue first mortgage bonds or preferred stock, it
is required to meet certain coverage requirements specified in its mortgage
indenture and corporate charter. The Company's ability to satisfy all coverage
requirements is such that it could issue new first mortgage bonds and preferred
stock to provide sufficient funds for all anticipated requirements.
ENVIRONMENTAL ISSUES
Clean Air Act
In November 1990, the Clean Air Act was signed into law. Title IV of the Clean
Air Act -- the acid rain compliance provision of the law -- significantly
impacted the operating companies of Southern Company, including Georgia Power.
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 initially affected 28 generating units in the Southern
electric system. As a result of Southern Company's compliance strategy, an
additional 22 generating units were brought into compliance with Phase I
requirements. Phase II compliance is required in 2000, and all fossil-fired
generating plants in the Southern electric system are affected.
Southern 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 Georgia Power's Phase I compliance totaled
approximately $167 million.
For Phase II sulfur dioxide compliance, Southern Company currently uses
emission allowances and increased fuel switching. 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 by $38
million.
The State of Georgia submitted a plan for nitrogen oxide emission reductions
in Atlanta's ozone non-attainment area on October 29, 1999. The Environmental
Protection Agency (EPA) found this plan to be deficient and required the State
to address the shortfalls of the plan. Based on the revised plan approved by the
Georgia Department of Natural Resources on January 26, 2000, the Company
estimates its capital expenditures to comply with the plan to be approximately
$713 million through 2003, of which $705 million remains to be spent. It is
still uncertain at this time what additional controls may be required at the
Company's plants beyond the recently submitted plan.
A significant portion of costs related to the acid rain provision 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.
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.
9
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 1999 Annual Report
Other Environmental Issues
In July 1997, the EPA revised the national ambient air quality standards for
ozone and particulate matter. This revision makes the standards significantly
more stringent. In September 1998, the EPA issued the final regional nitrogen
oxide rule to the states for implementation. The final rule affects 22 states
including Georgia. The EPA's July 1997 standards and the September 1998 rule are
being challenged in the courts by several states and industry groups.
Implementation of the final state rules for these three initiatives could
require substantial further reductions in nitrogen oxide and sulfur dioxide
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.
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, $6
million and $4 million in 1999, 1998 and 1997, 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.
The EPA and state environmental regulatory agencies are reviewing and
evaluating various matters including: nitrogen oxide emission control strategies
for ozone non-attainment areas; additional controls for hazardous air pollutant
emissions; control strategies to reduce regional haze; 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 1999 Annual Report contains forward-looking and historical
information. The Company cautions that there are various important factors that
could cause actual results to differ materially from those indicated in the
forward-looking information. Accordingly, there can be no assurance that such
indicated results will be realized. These factors include legislative and
regulatory initiatives regarding deregulation and restructuring of the electric
utility industry; 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 internal restructuring -- that may be
pursued by Southern Company; state and federal rate regulation; changes in or
application of environmental and other laws and regulations to which the Company
is subject; political, legal and economic conditions and developments; financial
market conditions and the results of financing efforts; changes in commodity
prices and interest rates; weather and other natural phenomena; and other
factors discussed in the reports--including Form 10-K--filed from time to time
by the Company with the Securities and Exchange Commission.
10
<PAGE>
<TABLE>
<CAPTION>
STATEMENTS OF INCOME
For the Years Ended December 31, 1999, 1998, 1997
Georgia Power Company 1999 Annual Report
- ---------------------------------------------------------------------------------------------------------------------------
1999 1998 1997
- ---------------------------------------------------------------------------------------------------------------------------
(in thousands)
<S> <C> <C> <C>
Operating Revenues:
Retail sales $4,050,088 $4,298,217 $3,978,299
Sales for resale --
Non-affiliates 210,104 259,234 282,365
Affiliates 76,426 81,606 38,708
Other revenues 120,057 99,196 86,345
- ----------------------------------------------------------------------------------------------------------------------------
Total operating revenues 4,456,675 4,738,253 4,385,717
- ----------------------------------------------------------------------------------------------------------------------------
Operating Expenses:
Operation --
Fuel 919,876 917,119 857,269
Purchased power --
Non-affiliates 214,573 229,960 143,409
Affiliates 174,989 161,003 177,240
Other 784,359 819,589 702,159
Maintenance 411,983 358,218 317,199
Depreciation and amortization 467,966 813,802 693,217
Taxes other than income taxes 202,853 204,623 207,192
Write down of Rocky Mountain plant - 33,536 -
- ----------------------------------------------------------------------------------------------------------------------------
Total operating expenses 3,176,599 3,537,850 3,097,685
- ----------------------------------------------------------------------------------------------------------------------------
Operating Income 1,280,076 1,200,403 1,288,032
Other Income (Expense):
Interest income 5,583 79,578 10,581
Equity in earnings of unconsolidated subsidiaries 2,721 3,735 4,266
Other, net (47,986) (38,277) (29,822)
- ----------------------------------------------------------------------------------------------------------------------------
Earnings Before Interest and Income Taxes 1,240,394 1,245,439 1,273,057
- ----------------------------------------------------------------------------------------------------------------------------
Interest Charges and Other:
Interest on long-term debt 162,303 180,746 194,344
Interest on notes payable 19,787 12,213 7,795
Amortization of debt discount, premium and expense, net (Note 3) 100,115 13,366 14,179
Other interest charges, net (2,336) 9,988 1,292
Distributions on preferred securities of subsidiary 65,774 54,327 47,369
- ----------------------------------------------------------------------------------------------------------------------------
Total interest charges and other, net 345,643 270,640 264,979
- ----------------------------------------------------------------------------------------------------------------------------
Earnings Before Income Taxes 894,751 974,799 1,008,078
Income taxes 351,639 398,632 395,155
- ----------------------------------------------------------------------------------------------------------------------------
Net Income 543,112 576,167 612,923
Dividends on Preferred Stock 1,729 5,939 18,927
- ----------------------------------------------------------------------------------------------------------------------------
Net Income After Dividends on Preferred Stock $ 541,383 $ 570,228 $ 593,996
============================================================================================================================
The accompanying notes are an integral part of these statements.
</TABLE>
11
<PAGE>
<TABLE>
<CAPTION>
STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 1999, 1998, and 1997
Georgia Power Company 1999 Annual Report
- --------------------------------------------------------------------------------------------------------------------------
1999 1998 1997
(in thousands)
<S> <C> <C> <C>
Operating Activities:
Net income $ 543,112 $ 576,167 $ 612,923
Adjustments to reconcile net income to net
cash provided from operating activities --
Depreciation and amortization 578,878 867,637 674,286
Deferred income taxes and investment tax credits, net (34,930) (93,005) (21,425)
Allowance for equity funds used during construction (734) (3,235) (6,012)
Amortization of deferred Plant Vogtle costs - 50,412 120,577
Other, net 43,555 (6,781) 1,991
Changes in certain current assets and liabilities --
Receivables, net 21,665 (25,453) 13,387
Inventories (32,582) (11,156) 39,748
Payables 13,095 47,862 (10,007)
Taxes accrued (2,832) 22,139 (3,596)
Energy cost recovery, retail (26,862) (7,649) (20,103)
Other 93,620 (15,142) (30,026)
- ----------------------------------------------------------------------------------------------------------------------------
Net cash provided from operating activities 1,195,985 1,401,796 1,371,743
- ----------------------------------------------------------------------------------------------------------------------------
Investing Activities:
Gross property additions (790,464) (499,053) (475,921)
Other (27,454) 67,031 16,223
- ----------------------------------------------------------------------------------------------------------------------------
Net cash used for investing activities (817,918) (432,022) (459,698)
- ----------------------------------------------------------------------------------------------------------------------------
Financing Activities:
Increase (decrease) in notes payable, net 295,389 (25,378) (64,266)
Proceeds --
Senior notes 100,000 495,000 -
Pollution control bonds 238,000 89,990 284,700
Preferred securities 200,000 - 364,250
Capital contributions from parent company 155,777 235 85
Retirements --
First mortgage bonds (404,000) (558,250) (60,258)
Pollution control bonds (235,000) (89,990) (284,700)
Preferred securities (100,000) - -
Preferred stock (36,231) (106,064) (356,392)
Capital distributions to parent company - (270,000) (205,000)
Special deposits -- redemption funds - - 44,454
Payment of preferred stock dividends (984) (9,137) (26,917)
Payment of common stock dividends (543,000) (536,600) (520,000)
Other (29,630) (26,641) (20,024)
- ----------------------------------------------------------------------------------------------------------------------------
Net cash used for financing activities (359,679) (1,036,835) (844,068)
- ----------------------------------------------------------------------------------------------------------------------------
Net Change in Cash and Cash Equivalents 18,388 (67,061) 67,977
- ----------------------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at Beginning of Year 16,272 83,333 15,356
- ----------------------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of Year $34,660 $16,272 $83,333
- ----------------------------------------------------------------------------------------------------------------------------
Supplemental Cash Flow Information:
Cash paid during the year for --
Interest (net of amount capitalized) $ 247,050 $ 269,524 $ 258,298
Income taxes (net of refunds) 394,457 480,318 427,596
- --------------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these statements.
</TABLE>
12
<PAGE>
<TABLE>
<CAPTION>
BALANCE SHEETS
At December 31, 1999 and 1998
Georgia Power Company 1999 Annual Report
- --------------------------------------------------------------------------------------------------------------------------
Assets 1999 1999
- --------------------------------------------------------------------------------------------------------------------------
(in thousands)
<S> <C> <C>
Current Assets:
Cash and cash equivalents $ 34,660 $ 16,272
Receivables --
Customer accounts receivable 438,161 439,420
Other accounts and notes receivable 102,544 99,574
Affiliated companies 16,006 16,817
ccumulated provision for uncollectible accounts (7,000) (5,500)
Fossil fuel stock, at average cost 126,298 104,133
Materials and supplies, at average cost 253,894 243,477
Other 63,990 73,280
- -------------------------------------------------------------------------------------------------------------------------
Total current assets 1,028,553 987,473
- -------------------------------------------------------------------------------------------------------------------------
Property, Plant, and Equipment:
In service 15,798,624 15,441,146
Less accumulated provision for depreciation 6,538,574 6,109,331
- -------------------------------------------------------------------------------------------------------------------------
9,260,050 9,331,815
Nuclear fuel, at amortized cost 119,288 121,169
Construction work in progress (Note 4) 425,975 189,849
- -------------------------------------------------------------------------------------------------------------------------
Total property, plant, and equipment 9,805,313 9,642,833
- -------------------------------------------------------------------------------------------------------------------------
Other Property and Investments:
Equity investments in unconsolidated subsidiaries (Note 4) 25,024 24,360
Nuclear decommissioning trusts 371,914 284,536
Other 33,766 34,781
- -------------------------------------------------------------------------------------------------------------------------
Total other property and investments 430,704 343,677
- -------------------------------------------------------------------------------------------------------------------------
Deferred Charges and Other Assets:
Deferred charges related to income taxes (Note 8) 590,893 604,488
Prepaid pension costs 145,801 103,606
Debt expense, being amortized 55,824 51,261
Premium on reacquired debt, being amortized 99,331 173,858
Other 120,441 126,422
- -------------------------------------------------------------------------------------------------------------------------
Total deferred charges and other assets 1,012,290 1,059,635
- -------------------------------------------------------------------------------------------------------------------------
Total Assets $12,276,860 $12,033,618
=========================================================================================================================
The accompanying notes are an integral part of these balance sheets.
</TABLE>
13
<PAGE>
<TABLE>
<CAPTION>
BALANCE SHEETS
At December 31, 1999 and 1998
Georgia Power Company 1999 Annual Report
- ---------------------------------------------------------------------------------------------------------------------------------
Liabilities and Stockholder's Equity 1999 1998
- ---------------------------------------------------------------------------------------------------------------------------------
(in thousands)
<S> <C> <C>
Current Liabilities:
Securities due within one year (Note 9) $ 155,772 $ 435,085
Notes payable 636,241 340,852
Accounts payable --
Affiliated 76,591 75,774
Other 346,785 326,317
Customer deposits 74,695 69,584
Taxes accrued --
Income taxes 7,914 15,801
Other 127,414 122,359
Interest accrued 58,665 60,187
Vacation pay accrued 38,143 34,443
Other 153,767 66,350
- ---------------------------------------------------------------------------------------------------------------------------------
Total current liabilities 1,675,987 1,546,752
- ---------------------------------------------------------------------------------------------------------------------------------
Long-Term Debt (See accompanying statements) 2,688,358 2,744,362
- ---------------------------------------------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes (Note 8) 2,202,565 2,249,613
Deferred credits related to income taxes (Note 8) 267,083 284,017
Accumulated deferred investment tax credits (Note 8) 367,114 381,914
Employee benefits provisions 181,529 177,148
Other 151,812 160,863
- ---------------------------------------------------------------------------------------------------------------------------------
Total deferred credits and other liabilities 3,170,103 3,253,555
- ---------------------------------------------------------------------------------------------------------------------------------
Company Obligated Mandatorily Redeemable Preferred
Securities Of Subsidiary Trusts Holding Company Junior
Subordinated Notes (See accompanying statements) 789,250 689,250
- ---------------------------------------------------------------------------------------------------------------------------------
Cumulative Preferred Stock (See accompanying statements) 14,952 15,527
- ---------------------------------------------------------------------------------------------------------------------------------
Common Stockholder's Equity (See accompanying statements) 3,938,210 3,784,172
- ---------------------------------------------------------------------------------------------------------------------------------
Total Liabilities and Stockholder's Equity $12,276,860 $12,033,618
=================================================================================================================================
The accompanying notes are an integral part of these balance sheets.
</TABLE>
14
<PAGE>
<TABLE>
<CAPTION>
STATEMENTS OF CAPITALIZATION
At December 31, 1999 and 1998
Georgia Power Company 1999 Annual Report
- ------------------------------------------------------------------------------------------------------------------------------------
1999 1998 1999 1998
- ------------------------------------------------------------------------------------------------------------------------------------
(in thousands) (percent of total)
Long-Term Debt:
First mortgage bonds --
Maturity Interest Rates
--------- ---------------
<S> <C> <C> <C> <C> <C>
September 1, 1999 6.125% $ - $ 195,000
March 1, 2000 6.00% 100,000 100,000
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
2023 through 2025 7.55% to 7.95% 57,000 266,000
- ----------------------------------------------------------------------------------------------------------
Total first mortgage bonds 492,000 896,000
- ----------------------------------------------------------------------------------------------------------
Pollution control bonds -- (Note 9)
Maturity Interest Rates
-------- --------------
2000 4.375% 50,000 50,000
2005 5.00% 57,000 57,000
2011 Variable (3.95% at 1/1/00) 10,450 10,450
2018-2019 6.00% to 6.35% 13,100 63,100
2020-2024 5.75% to 6.25% 192,270 377,270
2022-2024 Variable (3.70% to 5.05% at 1/1/00) 352,490 352,490
2025 6.00% to 6.10% 145,115 145,115
2025-2029 Variable (3.70% to 5.05% at 1/1/00) 475,765 475,765
2030-2034 Variable (3.70% to 5.05% at 1/1/00) 140,000 140,000
2034 5.25% to 5.45% 238,000 -
- ----------------------------------------------------------------------------------------------------------
Total pollution control bonds 1,674,190 1,671,190
- ----------------------------------------------------------------------------------------------------------
Senior notes -- (Note 9)
Maturity Interest Rates
-------- --------------
December 1, 2005 5.50% 150,000 150,000
December 31, 2038 6.60% 200,000 200,000
March 31, 2039 6.625% 100,000 -
December 31, 2047 6.875% 145,000 145,000
- ----------------------------------------------------------------------------------------------------------
Total senior notes 595,000 495,000
- ----------------------------------------------------------------------------------------------------------
Other long-term debt (Note 9) 85,851 86,280
- ----------------------------------------------------------------------------------------------------------
Unamortized debt discount, net (2,911) (4,679)
- ----------------------------------------------------------------------------------------------------------
Total long-term debt (annual interest
requirement -- $156,062,000) 2,844,130 3,143,791
Less amount due within one year (Note 9) 155,772 399,429
- ------------------------------------------------------------------------------------------------------------------------------------
Total long-term debt excluding amount due within one year $2,688,358 $2,744,362 36.2 % 38.0 %
- ------------------------------------------------------------------------------------------------------------------------------------
</TABLE>
15
<PAGE>
<TABLE>
<CAPTION>
STATEMENTS OF CAPITALIZATION (continued)
At December 31, 1999 and 1998
Georgia Power Company 1999 Annual Report
- -----------------------------------------------------------------------------------------------------------------------------------
1999 1998 1999 1998
- -----------------------------------------------------------------------------------------------------------------------------------
(in thousands) (percent of total)
Company Obligated Mandatorily
Redeemable Preferred Securities (Note 9):
<S> <C> <C> <C> <C>
$25 liquidation value -- 9.00% $ - $ 100,000
$25 liquidation value -- 7.75% 225,000 225,000
$25 liquidation value -- 7.60% 175,000 175,000
$25 liquidation value -- 7.75% 189,250 189,250
$25 liquidation value -- 6.85% 200,000 -
- -----------------------------------------------------------------------------------------------------------------------------------
Total (annual distribution requirement -- $59,104,000) 789,250 689,250 10.6 9.5
- -----------------------------------------------------------------------------------------------------------------------------------
Cumulative Preferred Stock, without par value:
Authorized -- 55,000,000 shares
Outstanding -- 149,520 shares at December 31, 1999
Outstanding -- 511,834 shares at December 31, 1998
$100 stated value --
4.60% to 6.60% 14,952 51,183
- ----------------------------------------------------------------------------------------------------------------------------------
Total cumulative preferred stock (annual dividend
requirement -- $688,000) 14,952 51,183
Less amount due within one year (Note 9) - 35,656
- -----------------------------------------------------------------------------------------------------------------------------------
Cumulative preferred stock excluding amount due within one year 14,952 15,527 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 1,815,983 1,660,206
Premium on preferred stock 40 158
Retained earnings (Note 9) 1,777,937 1,779,558
- -----------------------------------------------------------------------------------------------------------------------------------
Total common stockholder's equity (See accompanying statement) 3,938,210 3,784,172 53.0 52.3
- -----------------------------------------------------------------------------------------------------------------------------------
Total Capitalization $ 7,430,770 $ 7,233,311 100.0 % 100.0 %
- -----------------------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these statements.
</TABLE>
16
<PAGE>
<TABLE>
<CAPTION>
STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
For the Years Ended December 31, 1999, 1998, 1997
Georgia Power Company 1999 Annual Report
- ------------------------------------------------------------------------------------------------------------------------------
Premium on
Common Paid-In Preferred Retained
Stock Capital Stock Earnings Total
- ------------------------------------------------------------------------------------------------------------------------------
(in thousands)
<S> <C> <C> <C> <C> <C> <C>
Balance at January 1, 1997 $344,250 $2,134,886 $ 371 $1,674,774 $4,154,281
Net income after dividends on preferred stock - - - 593,996 593,996
Capital distributions to parent company - (205,000) - - (205,000)
Capital contributions from parent company - 85 - - 85
Cash dividends on common stock - - - (520,000) (520,000)
Preferred stock transactions, net - - (211) (3,423) (3,634)
- ------------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 1997 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
==============================================================================================================================
The accompanying notes are an integral part of these statements.
</TABLE>
17
<PAGE>
NOTES TO FINANCIAL STATEMENTS
Georgia Power Company 1999 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), a system service company, Southern Communications Services (Southern
LINC), Southern Energy, Inc. (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 operating
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. Southern Energy 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. Southern Energy'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 this act. The Company is also
subject to regulation by the FERC and the Georgia Public Service Commission
(GPSC). The Company follows generally accepted accounting principles (GAAP) and
complies with the accounting policies and practices prescribed by the respective
regulatory commissions. The preparation of financial statements in conformity
with GAAP 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 $253 million, $251
million, and $218 million during 1999, 1998, and 1997, 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 $270 million, $269 million, and $220
million during 1999, 1998, and 1997, 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's
1998 rate order, the Company recorded $85 million in 1999 of additional
amortization of premium on reacquired debt. See Note 3 under "Retail Rate
Orders" for additional information. Regulatory assets and (liabilities)
reflected in the Company's Balance Sheets at December 31 relate to the
following:
18
<PAGE>
NOTES (continued)
Georgia Power Company 1999 Annual Report
1999 1998
-----------------------
(in millions)
Deferred income taxes $ 591 $ 604
Deferred income tax credits (267) (284)
Premium on reacquired debt 99 174
Corporate building lease 54 53
Vacation pay 47 44
Postretirement benefits 33 36
Department of Energy assessments 24 26
Deferred nuclear outage costs 26 24
Other, net 3 12
- ---------------------------------------------------------------
Total $ 610 $ 689
===============================================================
In the event that a portion of the Company's operations is no longer subject
to the provisions of Statement No. 71, the Company would be required to write
off related regulatory assets and liabilities that are not specifically
recoverable through regulated rates. In addition, the Company would be required
to determine if any impairment to other assets exists, including plant, and
write down the assets, if impaired, to their fair value.
Revenues and Fuel Costs
The Company currently operates as a vertically integrated utility providing
electricity to retail customers within its traditional service area located
within the state of Georgia, and to wholesale customers in the Southeast.
The Company accrues revenues for service rendered but unbilled at the end of
each fiscal period. Fuel costs are expensed as the fuel is used. The Company's
electric rates include 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 $74
million in 1999, $74 million in 1998, and $76 million in 1997. 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.
Sufficient storage capacity currently is available to permit operation into 2003
at Plant Hatch and into 2017 at Plant Vogtle. Plant Vogtle's spent fuel storage
capacity includes the installation in 1998 of additional rack capacity.
Activities for adding dry cask storage capacity and potentially additional spent
fuel pool rack capacity at Plant Hatch during 2000 are in progress. In addition,
through Southern Nuclear, Georgia Power is a member of Private Fuel Storage,
LLC, a joint utility effort to develop a private spent fuel storage facility for
temporary storage of spent nuclear fuel. This facility is planned to begin
operation as early as the year 2003.
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. This fund will be
used by the DOE for the decontamination and decommissioning of its nuclear fuel
enrichment facilities. The assessment will be paid over a 15-year period, which
began in 1993. 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,
1999, to be approximately $21.4 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 1999, 3.2 percent in 1998, and 3.1 percent in 1997. In addition,
the Company recorded accelerated depreciation of electric plant of $314 million
in 1998 and $159 million in 1997. The Company did not record any accelerated
depreciation in 1999. These charges are recorded in the accumulated provision
for depreciation. See Note 3 under "Retail Rate Orders" for additional
information. When property subject to depreciation is retired or otherwise
disposed of in the normal course of business, its cost -- together with the cost
of removal, less salvage -- is charged to the accumulated provision for
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.
19
<PAGE>
NOTES (continued)
Georgia Power Company 1999 Annual Report
Nuclear Regulatory Commission (NRC) regulations require all licensees
operating commercial nuclear 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.
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 3.6 percent for
the Company's ownership interests are as follows:
Plant Plant
Hatch Vogtle
----------------------
Site study basis (year) 1997 1997
Decommissioning periods:
Beginning year 2014 2027
Completion year 2027 2038
- ---------------------------------------------------------------
(in millions)
Site study costs:
Radiated structures $372 $317
Non-radiated structures 33 44
- ---------------------------------------------------------------
Total $405 $361
===============================================================
(in millions)
Ultimate costs:
Radiated structures $722 $ 922
Non-radiated structures 65 129
- -------------------------------------------------------------
Total $787 $1,051
=============================================================
The decommissioning cost estimates are based on prompt dismantlement and
removal of the plant from service. The actual decommissioning costs may vary
from the above estimates because of changes in the assumed date of
decommissioning, changes in NRC requirements, changes in the assumptions used in
making estimates, changes in regulatory requirements, changes in technology, and
changes in costs of labor, materials, and equipment.
Annual provisions for nuclear decommissioning expense are based on an
annuity method as approved by the GPSC. The amounts expensed in 1999 and fund
balance as of December 31, 1999 were:
Plant Plant
Hatch Vogtle
- ---------------------------------------------------------------
(in millions)
Amount expensed in 1999 $ 17 $ 9
===============================================================
(in millions)
Accumulated provisions:
External trust funds, at fair value $222 $149
Internal reserves 22 12
- ---------------------------------------------------------------
Total $244 $161
===============================================================
Effective January 1, 1999, the GPSC increased the annual provision for
decommissioning expenses to $26 million from $20 million in 1998 and 1997. This
amount is based on the NRC generic estimate to decommission the radioactive
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.
20
<PAGE>
NOTES (continued)
Georgia Power Company 1999 Annual Report
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 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 1999, 1998 and 1997, the average AFUDC rates
were 5.61 percent, 6.71 percent and 7.60 percent, respectively. AFUDC, net of
taxes, as a percentage of net income after dividends on preferred stock, was
less than 2.0 percent for 1999, 1998, and 1997.
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'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, 1999 $2,758 $2,604
At December 31, 1998 3,058 3,105
Preferred securities:
At December 31, 1999 789 680
At December 31, 1998 689 716
- --------------------------------------------------------------
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. 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:
1999 1998
- -----------------------------------------------------------------
Discount 7.50% 6.75%
Annual salary increase 5.00 4.25
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
---------------------------
1999 1998
- ----------------------------------------------------------------
(in millions)
Balance at beginning of year $1,217 $1,119
Service cost 33 30
Interest cost 80 82
Benefits paid (57) (55)
Actuarial (gain) loss and
employee transfers (68) 41
- ----------------------------------------------------------------
Balance at end of year $1,205 $1,217
================================================================
21
<PAGE>
NOTES (continued)
Georgia Power Company 1999 Annual Report
Plan Assets
---------------------------
1999 1998
- ----------------------------------------------------------------
(in millions)
Balance at beginning of year $1,859 $1,931
Actual return on plan assets 313 11
Benefits paid (57) (55)
Employee transfers (8) (28)
- ----------------------------------------------------------------
Balance at end of year $2,107 $1,859
================================================================
The accrued pension costs recognized in the Balance Sheets
were as follows:
1999 1998
- ---------------------------------------------------------------
(in millions)
Funded status $ 902 $ 642
Unrecognized transition obligation (30) (35)
Unrecognized prior service cost 41 45
Unrecognized net actuarial gain (767) (548)
- ---------------------------------------------------------------
Prepaid asset recognized in the
Balance Sheets $ 146 $ 104
===============================================================
Components of the plans' net periodic cost were as follows:
1999 1998 1997
- ---------------------------------------------------------------
(in millions)
Service cost $ 33 $ 30 $ 30
Interest cost 80 82 82
Expected return on plan assets (137) (127) (121)
Recognized net actuarial gain (17) (20) (18)
Net amortization (1) (1) (1)
- ---------------------------------------------------------------
Net pension income $ (42) $ (36) $ (28)
===============================================================
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
---------------------------
1999 1998
- ----------------------------------------------------------------
(in millions)
Balance at beginning of year $464 $435
Service cost 8 7
Interest cost 30 32
Benefits paid (19) (16)
Actuarial loss and employee
transfers (45) 6
- ----------------------------------------------------------------
Balance at end of year $438 $464
=================================================================
Plan Assets
---------------------------
1999 1998
- ----------------------------------------------------------------
(in millions)
Balance at beginning of year $150 $122
Actual return on plan assets 11 4
Employer contributions 35 40
Benefits paid (19) (16)
- ----------------------------------------------------------------
Balance at end of year $177 $150
================================================================
The accrued postretirement costs recognized in the Balance Sheets were
as follows:
1999 1998
- ---------------------------------------------------------------
(in millions)
Funded status $(261) $(314)
Unrecognized transition obligation 122 131
Unrecognized net actuarial loss 10 57
Fourth quarter contributions 14 19
- ---------------------------------------------------------------
Accrued liability recognized in the
Balance Sheets $(115) $(107)
===============================================================
Components of the plans' net periodic cost were as follows:
1999 1998 1997
- ---------------------------------------------------------------
(in millions)
Service cost $ 8 $ 7 $ 7
Interest cost 30 32 32
Expected return on plan assets (10) (9) (7)
Recognized net actuarial loss 1 1 1
Net amortization 9 9 9
- ---------------------------------------------------------------
Net postretirement cost $ 38 $40 $42
===============================================================
An additional assumption used in measuring the accumulated postretirement
benefit obligations was a weighted average medical care cost trend rate of 7.74
percent for 1999, 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,
1999 as follows:
1 Percent 1 Percent
Increase Decrease
- ---------------------------------------------------------------
(in millions)
Benefit obligation $ 36 $ (30)
Service and interest costs 3 (3)
===============================================================
22
<PAGE>
NOTES (continued)
Georgia Power Company 1999 Annual Report
3. CONTINGENCIES & REGULATORY MATTERS
Retail Rate Orders
On December 18, 1998, the GPSC approved a new three-year rate order for the
Company. Under terms of the order, earnings will continue to be 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 1999 the Company recorded $85 million in accelerated amortization
of premium on reacquired debt. The Company also recorded $79 million of revenue
subject to refund for estimated earnings above 12.5 percent retail return on
common equity. Refunds will be made to customers in 2000. This refund is
presented in the financial statements under other current liabilities on the
Balance Sheet. The Company will not file for a general base rate increase unless
its projected retail return on common equity falls below 10 percent, and is
required to file a general rate case on July 1, 2001, in response to which the
GPSC would be expected to determine whether the rate order should be continued,
modified, or discontinued.
Under a previous three-year accounting order ending December 1998, the
Company's earnings were evaluated against a retail return on common equity range
of 10 percent to 12.5 percent. Earnings above 12.5 percent were used to
accelerate the amortization of regulatory assets or depreciation of electric
plant. Additionally, the Company was required to record $14 million annually of
accelerated depreciation of electric plant. During 1998 and 1997, for earnings
above the 12.5 percent retail return, the Company recorded charges of $292
million and $135 million, respectively. These charges are presented in the
financial statements as depreciation expense of electric plant and as an
addition to the accumulated provision for depreciation.
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
The State of Georgia submitted a plan for nitrogen oxide emission reductions in
Atlanta's ozone non-attainment area on October 29, 1999. The EPA found this plan
to be deficient and required the State to address the shortfalls of the plan.
Based on the revised plan approved by the Georgia Department of Natural
Resources on January 26, 2000, the Company estimates its capital costs to comply
with the plan to be approximately $713 million through 2003, of which $705
million remains to be spent. It is still uncertain at this time what additional
controls may be required at the Company's plants beyond the recently submitted
plan.
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
23
<PAGE>
NOTES (continued)
Georgia Power Company 1999 Annual Report
with respect to a site in Brunswick, Georgia. As of December 31, 1999, the
Company has recognized approximately $5 million in cumulative expenses
associated with this site. This represents the Company's agreed upon share of
removal and remedial investigation and feasibility study costs. 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.
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 31 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, 1999. The State has removed from
the list two power generation facilities following the assessment which
indicated no remediation was necessary. In addition, the Company has recognized
approximately $26 million in cumulative expenses through December 31, 1999 for
the assessment of the remaining sites on the list and the anticipated clean-up
cost for 12 sites that the Company plans to remediate. Any cost 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 $6 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.
The accrued costs for environmental remediation obligations are not
discounted to their present value.
Rocky Mountain Status
In June 1996, the GPSC initiated a review of the Rocky Mountain plant. On
January 14, 1998, the GPSC ordered that the Company be allowed approximately
$108 million of its $142 million investment in the plant in rate base as of
December 31, 1998. Under the rate order approved by the GPSC on December 18,
1998, the Company accepted the rate base allowance and, in December 1998,
recorded a charge to earnings of $21 million, after taxes, associated with the
write-down of the plant.
Tax Litigation
In August 1997, Southern Company and the Internal Revenue Service (IRS) entered
into a settlement agreement related to tax issues for the years 1984 through
1987. The agreement received final approval by the Joint Congressional Committee
on Taxation in June 1998 and as a result, the Company recognized interest income
in 1998 of $69 million. The refund by the IRS has been made and this matter is
now concluded.
Additionally, the Company received a refund from the State of Georgia
pertaining to the same issues and recognized an additional $4 million in
interest income in 1998.
Nuclear Performance Standards
The GPSC has adopted a nuclear performance standard for the Company's nuclear
generating units under which the performance of plants Hatch and Vogtle is
evaluated every three years. The performance standard is based on each unit's
capacity factor as compared to the average of all comparable U.S. nuclear units
operating at a capacity factor of 50 percent or higher during the three-year
period of evaluation. Depending on the performance of the units, the Company
could receive a monetary award or penalty under the performance standards
criteria.
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.
24
<PAGE>
NOTES (continued)
Georgia Power Company 1999 Annual Report
4. COMMITMENTS
Construction Program
The Company is constructing a ten unit, 800 megawatt combustion turbine peaking
power plant. Units one through eight will begin operation in 2000; units nine
and ten will begin operation in 2001. The Company also plans to construct a 570
megawatt combined cycle unit that will begin operation in 2002, and an addition
of two 568 megawatt combined cycle units at Plant Wansley, to begin operation in
2002. In addition, 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
$1.2 billion in 2000, $1.5 billion in 2001, and $1.5 billion in 2002.
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,
1999 were as follows:
Minimum
Year Obligations
- ---- ------------
(in millions)
2000 $ 659
2001 475
2002 381
2003 328
2004 300
2005 and beyond 787
- ----------------------------------------------------------------
Total minimum obligations $2,930
================================================================
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
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:
1999 1998 1997
---------------------------------
(in millions)
Energy $51 $45 $45
Capacity 29 30 30
- --------------------------------------------------------------
Total $80 $75 $75
==============================================================
Kilowatt-hours 3,338 3,146 3,038
- --------------------------------------------------------------
The Company has commitments regarding a portion of a 5 percent interest in
Plant Vogtle owned by 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 $57 million, $56 million, and
$54 million in 1999, 1998, and 1997, respectively. The current projected Plant
Vogtle capacity payments are:
Year Capacity Payments
- ---- ----------------------
(in millions)
2000 $ 60
2001 59
2002 58
2003 58
2004 55
2005 and beyond 594
- ----------------------------------------------------------------
Total capacity payments $ 884
================================================================
25
<PAGE>
NOTES (continued)
Georgia Power Company 1999 Annual Report
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,
1999 were as follows:
Year Other Obligations
- --- ----------------------
(in millions)
2000 $ 21
2001 22
2002 39
2003 41
2004 40
2005 and beyond 412
- ----------------------------------------------------------------
Total other obligations $ 575
================================================================
Operating Leases
The Company has entered into coal rail car rental agreements with various terms
and expiration dates. These expenses totaled $11 million for 1999, $13 million
for 1998, and $11 million for 1997. At December 31, 1999, estimated minimum
rental commitments for these noncancelable operating leases were as follows:
Year Minimum Obligations
- ---- --------------------------
(in millions)
2000 $ 12
2001 13
2002 13
2003 13
2004 13
2005 and beyond 115
- -----------------------------------------------------------------
Total minimum obligations $ 179
=================================================================
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
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 $21 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.
26
<PAGE>
NOTES (continued)
Georgia Power Company 1999 Annual Report
6. JOINT OWNERSHIP AGREEMENTS
Except as otherwise noted, the Company has contracted to operate and maintain
all jointly owned generating facilities. The Company includes its proportionate
share of plant operating expenses in the corresponding operating expenses in the
Statements of Income.
The Company jointly owns the Rocky Mountain pumped storage hydroelectric
plant with OPC 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 operated by FPC.
At December 31, 1999, 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% $3,297* $1,630
Plant Hatch (nuclear) 50.1 857 604
Plant Wansley (coal) 53.5 299 145
Plant Scherer (coal)
Units 1 and 2 8.4 112 51
Unit 3 75.0 544 193
Plant McIntosh
Common Facilities 75.0 19 1
(combustion-turbine)
Rocky Mountain 25.4 169* 66
(pumped storage)
Intercession City 33.3 11 **
(combustion-turbine)
- --------------------------------------------------------------------
* Investment net of write-offs.
** Less than $1 million.
7. LONG-TERM POWER SALES 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
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)
1999 $ 32 162
1998 32 162
1997 42 159
-------------------------------------
Unit power from specific generating plants is being sold to Florida Power &
Light Company (FP&L), FPC, Jacksonville Electric Authority (JEA), and the City
of Tallahassee, Florida. Under these agreements, the Company sold approximately
162 megawatts of capacity in 1999 and is scheduled to sell approximately 124
megawatts of capacity in 2000. After 2000, capacity sales will decline to
approximately 101 megawatts -- unless reduced by FP&L, FPC, and JEA -- until the
expiration of the contracts in 2010.
8. INCOME TAXES
At December 31, 1999, tax-related regulatory assets were $591 million and
tax-related regulatory liabilities were $267 million. The assets are
attributable to tax benefits flowed through to customers in prior years and to
taxes applicable to capitalized AFUDC. 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:
1999 1998 1997
-------------------------------
Total provision for income taxes: (in millions)
Federal:
Currently payable $ 333 $415 $352
Deferred -
Current year 114 131 49
Reversal of prior years (148) (218) (68)
Deferred investment tax
credits - 7 -
- -----------------------------------------------------------------
299 335 333
- -----------------------------------------------------------------
State:
Currently payable 54 77 65
Deferred -
Current year 5 18 8
Reversal of prior years (11) (31) (11)
Deferred investment tax
credits 5 - -
- -----------------------------------------------------------------
53 64 62
- -----------------------------------------------------------------
Total 352 399 395
=================================================================
27
<PAGE>
NOTES (continued)
Georgia Power Company 1999 Annual Report
The tax effects of temporary differences between the carrying amounts of
assets and liabilities in the financial statements and their respective tax
bases, which give rise to deferred tax assets and liabilities, are as follows:
1999 1998
-------------------
(in millions)
Deferred tax liabilities:
Accelerated depreciation $1,766 $1,670
Property basis differences 729 854
Other 155 158
- -----------------------------------------------------------------
Total 2,650 2,682
- -----------------------------------------------------------------
Deferred tax assets:
Other property basis differences 200 211
Federal effect of state deferred taxes 93 95
Other deferred costs 109 96
Disallowed Plant Vogtle buybacks 22 23
Other 26 21
- -----------------------------------------------------------------
Total 450 446
- -----------------------------------------------------------------
Net deferred tax liabilities 2,200 2,236
Portion included in current assets 3 13
- -----------------------------------------------------------------
Accumulated deferred income taxes
in the Balance Sheets $2,203 $2,249
=================================================================
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 $20 million in 1999, $22 million in 1998, and $15 million in 1997.
At December 31, 1999, all investment tax credits available to reduce federal
income taxes payable had been utilized.
A reconciliation of the federal statutory tax rate to the effective income
tax rate is as follows:
1999 1998 1997
--------------------------
Federal statutory rate 35% 35% 35%
State income tax, net of
federal deduction 4 4 4
Non-deductible book
depreciation 2 6 4
Other (2) (4) (4)
- ---------------------------------------------------------------
Effective income tax rate 39% 41% 39%
===============================================================
Southern Company and its subsidiaries file a consolidated federal income tax
return. Under a joint consolidated income tax agreement, each subsidiary's
current and deferred tax expense is computed on a stand-alone basis.
9. CAPITALIZATION
First Mortgage Bond Indenture & Charter Restrictions
The Company historically has relied on issuances of first mortgage bonds and
preferred stock, in addition to pollution control revenue bonds issued for its
benefit by public authorities, to meet its long-term external financing
requirements. Recently, the Company's financings have consisted of unsecured
debt and trust preferred securities. In this regard, the Company sought and
obtained stockholder approval in 1997 to amend its corporate charter eliminating
restrictions on the amounts of unsecured indebtedness it may incur.
The Company's first mortgage bond indenture contains various restrictions
that remain in effect as long as the bonds are outstanding. At December 31,
1999, $881 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.
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.
28
<PAGE>
NOTES (continued)
Georgia Power Company 1999 Annual Report
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 $457.5 million of its
first mortgage bonds outstanding at December 31, 1999, 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
The Company incurred debt in connection with the issuance of unsecured senior
notes. 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 2000, the Company had unused credit arrangements with banks
totaling $1.3 billion, of which $752 million expires at various times during
2000, and $500 million expires at April 24, 2003.
Of the total $1.3 billion in unused credit, $1 billion is a syndicated
credit arrangement with $500 million expiring April 20, 2000, and $500 million
expiring April 24, 2003. Both agreements provide the option of converting
borrowings into two-year term loans upon expiration date. The agreements contain
stated borrowing rates but also allow for competitive bid loans. In addition,
the agreements require payment of commitment fees based on the unused portions
of the commitments. Annual fees are also paid to the agent bank.
Approximately $162 million of the $752 million arrangements expiring during
2000 allow for two-year term loans executable upon expiration date of the
facilities. The $30 million credit arrangement expiring at May 1, 2000, allows
for term loans of up to three years. 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.
These unused credit arrangements provide 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,
1999, was $250 million.
In addition, the Company borrows under uncommitted lines of credit with
banks and through a $500 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 1999.
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, 1999 and 1998, 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, 1999 and 1998, the interest and lease amortization deferred on
the Balance Sheets are $54 million and $53 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.
29
<PAGE>
NOTES (continued)
Georgia Power Company 1999 Annual Report
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:
1999 1998
------------------
(in millions)
Bond improvement fund requirements $ 5 $ 9
Capital lease - current portion 1 -
First mortgage bond maturities
and redemptions 100 390
Pollution control bond maturities
and redemptions 50 -
- ---------------------------------------------------------------
Total long-term debt 156 399
Preferred stock - 36
- ---------------------------------------------------------------
Total $156 $435
===============================================================
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 stock 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. In general, for the first five years a series of first
mortgage bonds is outstanding, the Company is prohibited from redeeming for
improvement fund purposes more than 1 percent annually of the original issue
amount.
10. QUARTERLY FINANCIAL DATA (UNAUDITED)
Summarized quarterly financial information for 1999 and 1998 is as follows:
Net Income
After
Dividends on
Operating Operating Preferred
Quarter Ended Revenues Income Stock
- ---------------------------------------------------------------------
(in millions)
--------------------------------------------
March 1999 $ 931 $224 $ 92
June 1999 1,092 299 138
September 1999 1,466 557 296
December 1999 968 200 15
March 1998 $ 984 $257 $ 106
June 1998 1,226 286 137
September 1998 1,530 514 255
December 1998 998 143 72
- ---------------------------------------------------------------------
Under the 1998 rate order, the Company recorded $85 million of accelerated
amortization which was recorded monthly throughout 1999 as an operating expense.
See Note 3 to the financial statements under "Retail Rate Orders" for additional
information. In December 1999, in accordance with the order, the Company
reclassified this $85 million to amortization of premium on reacquired debt. The
1999 fourth quarter operating income reflects this reclassification.
The quarterly operating income data above has been reclassified to reflect
the Company's current presentation of income tax expense.
The Company's business is influenced by seasonal weather conditions.
30
<PAGE>
<TABLE>
<CAPTION>
SELECTED FINANCIAL AND OPERATING DATA 1995-1999
Georgia Power Company 1999 Annual Report
- --------------------------------------------------------------------------------------------------------------------------------
1999 1998 1997 1996 1995
- --------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Operating Revenues (in thousands) $4,456,675 $4,738,253 $4,385,717 $4,416,779 $4,405,338
Net Income after Dividends
on Preferred Stock (in thousands) $541,383 $570,228 $593,996 $580,327 $608,862
Cash Dividends
on Common Stock (in thousands) $543,000 $536,600 $520,000 $475,500 $451,500
Return on Average Common Equity (percent) 14.02 14.61 14.53 13.73 14.43
Total Assets (in thousands) $12,276,860 $12,033,618 $12,573,728 $13,006,635 $13,470,275
Gross Property Additions (in thousands) $790,464 $499,053 $475,921 $428,220 $480,449
- --------------------------------------------------------------------------------------------------------------------------------
Capitalization (in thousands):
Common stock equity $3,938,210 $3,784,172 $4,019,728 $4,154,281 $4,299,012
Preferred stock 14,952 15,527 157,247 464,611 692,787
Company obligated mandatorily
redeemable preferred securities 789,250 689,250 689,250 325,000 100,000
Long-term debt 2,688,358 2,744,362 2,982,835 3,200,419 3,315,460
- --------------------------------------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) $7,430,770 $7,233,311 $7,849,060 $8,144,311 $8,407,259
================================================================================================================================
Capitalization Ratios (percent):
Common stock equity 53.0 52.3 51.2 51.0 51.1
Preferred stock 0.2 0.2 2.0 5.7 8.2
Company obligated mandatorily
redeemable preferred securities 10.6 9.5 8.8 4.0 1.2
Long-term debt 36.2 38.0 38.0 39.3 39.5
- --------------------------------------------------------------------------------------------------------------------------------
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+
Duff & Phelps AA- AA- AA- AA- AA-
Preferred Stock -
Moody's a2 a2 a2 a2 a2
Standard and Poor's A- A A A A
Duff & Phelps 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
Duff & Phelps A+ A+ A+ A+ A+
================================================================================================================================
Customers (year-end):
Residential 1,632,450 1,596,488 1,561,675 1,531,453 1,500,024
Commercial 229,524 221,180 211,672 205,087 198,624
Industrial 8,958 9,485 9,988 10,424 10,796
Other 3,060 3,034 2,748 2,645 2,568
- --------------------------------------------------------------------------------------------------------------------------------
Total 1,873,992 1,830,187 1,786,083 1,749,609 1,712,012
================================================================================================================================
Employees (year-end): 8,961 8,371 8,354 10,346 11,061
- --------------------------------------------------------------------------------------------------------------------------------
</TABLE>
31
<PAGE>
<TABLE>
<CAPTION>
SELECTED FINANCIAL AND OPERATING DATA 1995-1999 (continued)
Georgia Power Company 1999 Annual Report
- -------------------------------------------------------------------------------------------------------------------------------
1999 1998 1997 1996 1995
- -------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Operating Revenues (in thousands):
Residential $ 1,410,099 $1,486,699 $ 1,326,787 $ 1,371,033 $ 1,337,060
Commercial 1,527,880 1,591,363 1,493,353 1,486,586 1,449,108
Industrial 1,143,001 1,170,881 1,110,311 1,118,633 1,141,766
Other (30,892) 49,274 47,848 47,060 44,255
- -------------------------------------------------------------------------------------------------------------------------------
Total retail 4,050,088 4,298,217 3,978,299 4,023,312 3,972,189
Sales for resale - non-affiliates 210,104 259,234 282,365 281,580 290,302
Sales for resale - affiliates 76,426 81,606 38,708 35,886 76,906
- -------------------------------------------------------------------------------------------------------------------------------
Total revenues from sales of electricity 4,336,618 4,639,057 4,299,372 4,340,778 4,339,397
Other revenues 120,057 99,196 86,345 76,001 65,941
- -------------------------------------------------------------------------------------------------------------------------------
Total $4,456,675 $4,738,253 $4,385,717 $4,416,779 $4,405,338
===============================================================================================================================
Kilowatt-Hour Sales (in thousands):
Residential 19,404,709 19,481,486 17,295,022 17,826,451 17,307,399
Commercial 23,715,485 22,861,391 21,134,346 20,823,073 19,844,999
Industrial 27,300,355 27,283,147 26,701,685 26,191,831 25,286,340
Other 551,451 543,462 538,163 536,057 493,720
- -------------------------------------------------------------------------------------------------------------------------------
Total retail 70,972,000 70,169,486 65,669,216 65,377,412 62,932,458
Sales for resale - non-affiliates 5,060,931 6,438,891 6,795,300 7,868,342 6,591,841
Sales for resale - affiliates 1,795,243 2,038,400 1,706,699 1,180,207 2,738,947
- -------------------------------------------------------------------------------------------------------------------------------
Total 77,828,174 78,646,777 74,171,215 74,425,961 72,263,246
===============================================================================================================================
Average Revenue Per Kilowatt-Hour (cents):
Residential 7.27 7.63 7.67 7.69 7.73
Commercial 6.44 6.96 7.07 7.14 7.30
Industrial 4.19 4.29 4.16 4.27 4.52
Total retail 5.71 6.13 6.06 6.15 6.31
Sales for resale 4.18 4.02 3.78 3.51 3.94
Total sales 5.57 5.90 5.80 5.83 6.00
Residential Average Annual
Kilowatt-Hour Use Per Customer 12,006 12,314 11,171 11,763 11,654
Residential Average Annual
Revenue Per Customer $872.47 $939.73 $857.01 $904.70 $900.28
Plant Nameplate Capacity
Ratings (year-end) (megawatts) 14,474 14,437 14,437 14,367 14,344
Maximum Peak-Hour Demand (megawatts):
Winter 11,568 11,959 10,407 10,410 9,819
Summer 14,575 13,923 13,153 12,914 12,828
Annual Load Factor (percent) 58.9 58.7 57.4 62.2 59.6
Plant Availability (percent):
Fossil-steam 84.3 86.0 85.8 85.2 85.8
Nuclear 89.3 91.6 88.8 89.3 91.8
- -------------------------------------------------------------------------------------------------------------------------------
Source of Energy Supply (percent):
Coal 63.0 62.3 64.3 60.4 63.0
Nuclear 18.0 18.3 18.8 18.2 19.3
Hydro 0.9 2.2 2.2 2.2 2.5
Oil and gas 1.6 2.2 0.6 0.5 0.6
Purchased power -
From non-affiliates 6.6 6.5 2.7 5.6 7.7
From affiliates 9.9 8.5 11.4 13.1 6.9
- -------------------------------------------------------------------------------------------------------------------------------
Total 100.0 100.0 100.0 100.0 100.0
===============================================================================================================================
</TABLE>
32
