MANAGEMENT'S REPORT
Georgia Power Company 1998 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/ H. Allen Franklin
H. Allen Franklin
President and Chief
Executive Officer
/s/ David M. Ratcliffe
David M. Ratcliffe
Executive Vice President,
Treasurer and Chief
Financial Officer
February 10, 1999
1
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To Georgia Power Company:
We have audited the accompanying balance sheets and statements of capitalization
of Georgia Power Company (a Georgia corporation and a wholly owned subsidiary of
Southern Company) as of December 31, 1998 and 1997, and the related statements
of income, retained earnings, paid-in capital, and cash flows for each of the
three years in the period ended December 31, 1998. 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 generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements (pages 13-33) referred to above
present fairly, in all material respects, the financial position of Georgia
Power Company as of December 31, 1998 and 1997, and the results of its
operations and its cash flows for each of the three years in the period ended
December 31, 1998, in conformity with generally accepted accounting principles.
/s/ Arthur Andersen LLP
Arthur Andersen LLP
Atlanta, Georgia
February 10, 1999
2
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL
CONDITION
Georgia Power Company 1998 Annual Report
RESULTS OF OPERATIONS
Earnings
Georgia Power Company's 1998 earnings totaled $570 million, representing a $24
million (4.0 percent) decrease from 1997. This earnings decrease resulted
primarily from higher operating expenses, additional depreciation charges
pursuant to a Georgia Public Service Commission (GPSC) retail accounting order
discussed below, lower wholesale capacity 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 increased
non-operating income. Earnings for 1997 totaled $594 million, representing a $14
million (2.4 percent) increase over 1996. This earnings increase resulted
primarily from lower operating expenses, lower financing costs, and increased
non-operating income, partially offset by lower retail revenues and additional
depreciation charges pursuant to the GPSC retail accounting order.
Revenues
The following table summarizes the factors impacting operating revenues for the
1996-1998 period:
Increase (Decrease)
From Prior Year
------------------------------------
1998 1997 1996
------------------------------------
Retail - (in millions)
Sales growth $ 174 $ 62 $ 58
Weather 101 (74) (25)
Fuel cost recovery 70 (30) 28
Demand-side programs (25) (3) (10)
- --------------------------------------------------------------------
Total retail 320 (45) 51
- --------------------------------------------------------------------
Sales for resale -
Non-affiliates (23) 1 (9)
Affiliates 43 3 (41)
- --------------------------------------------------------------------
Total sales for resale 20 4 (50)
- --------------------------------------------------------------------
Other operating revenues 13 10 10
- --------------------------------------------------------------------
Total operating revenues $ 353 $ (31) $ 11
====================================================================
Percent change 8.0% (0.7)% 0.3%
- --------------------------------------------------------------------
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. Retail revenues of $4.0 billion in 1997 decreased $45 million (1.1
percent) from 1996 primarily due to milder-than-normal weather, as well as
commercial and industrial customers taking advantage of load management rates.
Fuel revenues generally represent the direct recovery of fuel expense,
including the fuel component of purchased energy, and do not affect net income.
Revenues from demand-side option programs generally represent the direct
recovery of program costs. See Note 3 to the financial statements under
"Demand-Side Conservation Programs" for further information on these programs.
Wholesale revenues from sales to non-affiliated utilities decreased slightly
in 1998 and were as follows:
1998 1997 1996
-------------------------------
(in millions)
Outside service area -
Long-term contracts $ 51 $ 71 $ 84
Other sales 94 80 37
Inside service area 115 132 161
- ---------------------------------------------------------------
Total $260 $283 $282
===============================================================
Revenues from long-term contracts outside the service area decreased in 1998
primarily due to lower capacity charges and decreased energy sales and in 1997
primarily due to scheduled reductions in the amount of megawatt-hour capacity
under these contracts. See Note 7 to the financial statements for further
information regarding these sales. Revenues from other sales outside the service
area increased in 1998 and 1997 primarily due to power marketing activities.
These increases were primarily offset by increases in purchased power from
non-affiliates and, as a result, had no significant effect on net income.
Wholesale revenues from customers within the service area decreased in 1998 and
1997 primarily due to a decrease in revenues under a power supply agreement with
Oglethorpe Power Corporation (OPC). OPC decreased its purchases of capacity by
250 megawatts each in September 1996, 1997, and 1998 and has notified the
Company of its intent to decrease purchases of capacity by an additional 250
megawatts in September 1999 and 125 megawatts in September 2000.
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
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 1998 Annual Report
Kilowatt-hour (KWH) sales for 1998 and the percent change by year were as
follows:
Percent Change
----------------------------
1998
KWH 1998 1997 1996
-----------------------------------------
(in billions)
Residential 19.5 12.6% (3.0)% 3.0%
Commercial 22.9 8.2 1.5 4.9
Industrial 27.3 2.2 1.9 3.6
Other 0.5 1.0 0.4 8.6
--------
Total retail 70.2 6.9 0.4 3.9
--------
Sales for resale -
Non-affiliates 6.4 (5.2) (13.6) 19.4
Affiliates 2.0 19.4 44.6 (56.9)
--------
Total sales for resale 8.4 (0.3) (6.0) (3.0)
--------
Total sales 78.6 6.0 (0.3) 3.0
========
- ------------------------------------------------------------------
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. Residential sales in 1997 declined 3.0 percent while sales
to commercial and industrial customers increased slightly by 1.5 percent and 1.9
percent, respectively. Milder-than-normal temperatures experienced in 1997
contributed to the moderate sales.
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:
1998 1997 1996
-------------------------
Total generation
(billions of KWH) 69.1 66.5 63.7
Sources of generation
(percent) --
Coal 73.3 74.8 74.3
Nuclear 21.6 21.8 22.4
Hydro 2.6 2.7 2.7
Oil and gas 2.5 0.7 0.6
Average cost of fuel per net
KWH generated
(cents) -- 1.36 1.32 1.35
- ---------------------------------------------------------------
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. Fuel
expense increased 2.6 percent in 1997 primarily due to an increase in
generation, partially offset by a lower average cost of fuel.
Purchased power expense increased $70 million (21.9 percent) to meet higher
energy demands and power marketing activities. The majority of the energy
purchased for power marketing activities was resold to non-affiliated third
parties and had no significant effect on net income. In June 1998, the Company
began purchasing capacity and energy from a 300 megawatt cogeneration facility
pursuant to a 30-year purchase power agreement. Purchased power expense
decreased $66 million (17.1 percent) in 1997 primarily due to decreased
purchases from affiliated companies and declines in contractual capacity buyback
purchases from the co-owners of Plant Vogtle. Under the terms of the 1991 retail
rate order, the costs of declining Plant Vogtle contractual capacity buyback
purchases were levelized over a six-year period ending September 1997. The
levelization is reflected in the amortization of deferred Plant Vogtle costs in
the Statements of Income. See Note 1 to the financial statements under "Plant
Vogtle Phase-In Plans" for additional information.
4
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 1998 Annual Report
Other operation and maintenance (O&M) expenses, excluding the provision for
separation benefits, increased 15.9 percent primarily due to continuing expenses
related to a new customer service system implemented in January 1998,
modification of certain information systems for year 2000 compliance discussed
below, an increase in outage costs at steam power generating facilities, and
increased line maintenance. Other O&M expenses, excluding the provision for
separation benefits, decreased 4.1 percent in 1997 primarily due to initiatives
in 1996 to reduce fossil generation materials inventory levels and an adjustment
in 1996 to deferred postretirement benefits to reflect changes in the retiree
benefits plan.
Depreciation and amortization increased $191 million in 1998 and $140
million in 1997 primarily due to accelerated depreciation of generating plant
pursuant to the retail accounting order and an increase in plant-in-service. See
Note 3 to the financial statements under "Retail Rate Order" for additional
information.
The Company has deferred certain expenses and recorded a deferred return
related to Plant Vogtle under phase-in plans. The amortization of deferred Plant
Vogtle costs reflects the completion in September 1997 of the amortization of
the levelized buybacks and the Plant Vogtle Unit 1 cost deferrals under a 1987
GPSC order. In December 1998, the remaining Vogtle Unit 2 cost deferrals were
fully amortized to expense under a 1998 retail rate order. See Note 1 to the
financial statements under "Plant Vogtle Phase-In Plans" for information
regarding the deferral and subsequent amortization of costs related to Plant
Vogtle.
Additionally, 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. See Note 3 to the financial statements
under "Rocky Mountain Plant Status" for additional information.
Other income (expense) increased in 1998 primarily due to the recognition of
$73 million in interest income resulting from the resolution of tax issues with
the Internal Revenue Service (IRS) and the State of Georgia. Other income
(expense) increased in 1997 primarily due to increased tax benefits from losses
of the parent company allocated to the Company under the joint consolidated
income tax agreement between Southern Company and its subsidiaries. See Note 8
to the financial statements for additional information.
Total financing costs decreased in 1998 and 1997. These changes were
primarily due to the refinancing or retirement of securities. The Company
refinanced or retired $754 million and $701 million of securities in 1998 and
1997, respectively. Dividends on preferred stock decreased $13 million and $26
million in 1998 and 1997, respectively. These decreases were partially offset by
increases in interest and other charges of $6 million and $17 million in 1998
and 1997, respectively, primarily due to the issuance of additional mandatorily
redeemable preferred securities in 1996 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.
5
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 1998 Annual Report
On January 1, 1999, the Company began operating under a new three-year
retail rate order approved by the GPSC on December 18, 1998. 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 in excess of
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 in excess of the 12.5 percent return will be applied to rate
reductions, with the remaining one-third retained by the Company. 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 Order"
for additional information.
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 in excess of 12.5 percent were used to
accelerate the amortization of regulatory assets or depreciation of electric
plant.
As a result of the Company recognizing the write-off of a portion of its
cost in the Rocky Mountain plant and completing the amortization of deferred
Plant Vogtle costs in 1998 in accordance with the new retail rate order, future
depreciation and amortization will decrease. Future depreciation and
amortization will also decrease as a result of the cap on the amount of
accelerated amortization or depreciation of assets under the new retail rate
order. See Note 3 to the financial statements under "Retail Rate Order" for
additional information.
Growth in energy sales is subject to a number of factors which traditionally
have included changes in contracts with neighboring utilities, energy
conservation practiced by customers, the elasticity of demand, weather,
competition, initiatives to increase sales to existing customers, and the rate
of economic growth in the Company's service area. Assuming normal weather,
retail sales growth is projected to be approximately 2 percent annually on
average during 1999 through 2001.
In September 1998, OPC decreased its purchases of capacity under a power
supply agreement by 250 megawatts and has notified the Company of its intent to
decrease purchases of capacity by an additional 250 megawatts in September 1999
and 125 megawatts in September 2000. As a result, the Company's capacity
revenues from OPC will decline by approximately $23 million in 1999, an
additional $19 million in 2000, and an additional $4 million in 2001. Under the
amended 1995 Integrated Resource Plan approved by the GPSC in March 1997, the
resources associated with the decreased purchases in 1998 will be used to meet
the needs of the Company's retail customers through 2004. See Note 3 to the
financial statements under "FERC Review of Equity Returns" for additional
information about other wholesale regulatory matters.
The Company has entered into a five-year purchase power agreement scheduled
to begin in June 2000 for approximately 215 megawatts. Capacity and fixed O&M
payments are estimated to be between $7 million and $8 million each year.
The Company plans to construct an eight unit, 600-megawatt combustion
turbine peaking power plant that will begin operation in 2000 and will serve the
wholesale market. The plant will supply power to fulfill a contract for 400
megawatts of peaking power already established with the Company. The addition of
this facility will increase related O&M and depreciation expenses for the
Company. Because the plant will be dedicated to the wholesale market, retail
rates will not be affected. The Company may expand the facility to a total of
1,200 to 1,900 megawatts of capacity over the next two to three years in order
to meet additional anticipated wholesale power demand.
Compliance costs related to current and future environmental laws and
regulations could affect earnings if such costs are not fully recovered. The
Clean Air Act and other important environmental items are discussed further
under "Environmental Issues."
6
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 1998 Annual Report
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. This enhances the incentive for IPPs to build cogeneration plants for
a utility's large industrial and commercial customers and sell electric energy
to other utilities. Also, electricity sales for resale rates are being driven
down by wholesale transmission access and numerous potential new energy
suppliers, including power marketers and brokers. 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.
The Company continues to compete with other electric suppliers within the
state. In Georgia, most new retail customers with at least 900 kilowatts of
connected load may choose their electricity supplier. Numerous federal and state
initiatives are in varying stages to promote wholesale and retail competition
across the nation. Among other things, these initiatives allow customers to
choose their electricity provider. As these initiatives materialize, the
structure of the utility industry could radically change. Some states have
approved initiatives that result in a separation of the ownership and/or
operation of generating facilities from the ownership and/or operation of
transmission and distribution facilities. While the GPSC has held workshops to
discuss retail competition and industry restructuring, there has been no
proposed or enacted legislation to date in Georgia. Enactment would require
numerous issues to be resolved, including significant ones relating to
transmission pricing and recovery of costs. The GPSC plans to release a schedule
and procedure order for a stranded costs docket in the first half of 1999. The
ability 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 Order" 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.
7
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 1998 Annual Report
Year 2000
Year 2000 Challenge
In order to save storage space, computer programmers in the 1960s and 1970s
shortened the year portion of date entries to just two digits. Computers
assumed, in effect, that all years began with "19." This practice was widely
adopted and hard-coded into computer chips and processors found in some
equipment. This approach, intended to save processing time and storage space,
was used until the mid-1990s. Unless corrected before the year 2000, affected
software systems and devices containing a chip or microprocessor with date and
time functions could incorrectly process dates or the systems may cease to
function.
The Company depends on complex computer systems for many aspects of its
operations, which include generation, transmission, and distribution of
electricity, as well as other business support activities. The Company's goal is
to have critical devices or software that are required to maintain operations to
be Year 2000 ready by June 1999. Year 2000 ready means that a system or
application is determined suitable for continued use through the Year 2000 and
beyond. Critical systems include, but are not limited to, reactor control
systems, safe shutdown systems, turbine generator systems, control center
computer systems, customer service systems, energy management systems, and
telephone switches and equipment.
Year 2000 Program and Status
The Company's executive management recognizes the seriousness of the Year 2000
challenge and has dedicated what it believes to be adequate resources to address
the issue. The Millennium Project is a team of employees, IBM consultants, and
other contractors whose progress is reviewed on a monthly basis by a steering
committee of Southern Company executives.
The Company's Year 2000 program was divided into two phases. Phase I began
in 1996 and consisted of identifying and assessing corporate assets related to
software systems and devices that contain a computer chip or clock. The first
phase was completed in June 1997. Phase 2 consists of testing and remediating
high priority systems and devices. Also, contingency planning is included in
this phase. Completion of Phase 2 is targeted for June 1999. The Millennium
Project will continue to monitor the affected computer systems, devices, and
applications into the year 2000.
The Southern Company has completed more than 70 percent of the activities
contained in its work plan. The percentage of completion and projected
completion by function are as follows:
- ------------------------------------------------------------------------------
Work Plan
----------------------------------------------------
Remediation Project
Inventory Assessment Testing Completion
- -----------------------------------------------------------------------------
Generation 100% 100% 70% 6/99
- -----------------------------------------------------------------------------
Energy Management 100 100 90 6/99
- -----------------------------------------------------------------------------
Transmission and
Distribution 100 100 100 1/99
- -----------------------------------------------------------------------------
Telecommunications 100 100 50 6/99
- -----------------------------------------------------------------------------
Corporate Applications 100 100 90 3/99
- -----------------------------------------------------------------------------
Year 2000 Costs
Current projected total costs for Year 2000 readiness, including the Company's
share of costs of Southern Nuclear Operating Company, are approximately $38
million. These costs include labor necessary to identify, test, and renovate
affected devices and systems. From its inception through December 31, 1998, the
Year 2000 program costs, recognized as expense, amounted to $27 million.
Year 2000 Risks
The Company is implementing a detailed process to minimize the possibility of
service interruptions related to the Year 2000. The Company believes, based on
current tests, that the system can provide customers with electricity. These
tests increase confidence, but do not guarantee error-free operation. The
Company is taking what it believes to be prudent steps to prepare for the Year
2000, and it expects any interruptions in service that may occur within the
service territory to be isolated and short in duration.
The Company expects the risks associated with Year 2000 to be no more severe
than the scenarios that its electric system is routinely prepared to handle. The
most likely worst case scenario consists of the service loss of one of the
largest generating units and/or the service loss of any single bulk transmission
element in its service territory. The Company has followed a proven methodology
8
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 1998 Annual Report
for identifying and assessing software and devices containing potential Year
2000 challenges. Remediation and testing of those devices are in progress.
Following risk assessment, the Company is preparing contingency plans as
appropriate and is participating in North American Electric Reliability Council
- - coordinated national drills during 1999.
The Company is currently reviewing the Year 2000 readiness of material third
parties that provide goods and services crucial to the Company's operations.
Among such critical third parties are fuel, transportation, telecommunications,
water, chemical, and other suppliers. Contingency plans based on the assessment
of each third party's ability to continue supplying critical goods and services
to the Company are being developed.
There is a potential for some earnings erosion caused by reduced electrical
demand by customers because of their Year 2000 issues.
Year 2000 Contingency Plans
Because of experience with hurricanes and other storms, the Company is skilled
at developing and using contingency plans in unusual circumstances. As part of
Year 2000 business continuity and contingency planning, the Company is drawing
on that experience to make risk assessments and is developing additional plans
to deal specifically with situations that could arise relative to Year 2000
challenges. The Company is identifying critical operational locations, and key
employees will be on duty at those locations during the Year 2000 transition. In
September 1999, drills are scheduled to be conducted to test contingency plans.
Because of the level of detail of the contingency planning process, management
feels that the contingency plans will keep any service interruptions that may
occur within the service territory isolated and short in duration.
Exposure to Market Risks
Due to cost-based rate regulation, the Company has limited exposure to market
volatility in interest rates and prices of electricity. 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, 1998, 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, 1998, a near-term 100 basis point change in interest rates would not
materially affect the financial statements.
New Accounting Standards
The FASB has issued Statement No. 133, Accounting for Derivative Instruments and
Hedging Activities, which must be adopted by the year 2000. This statement
establishes accounting and reporting standards for derivative instruments -
including certain derivative instruments embedded in other contracts - and for
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.
In March 1998, the American Institute of Certified Public Accountants (AICPA)
issued a new Statement of Position, Accounting for the Costs of Computer
Software Developed or Obtained for Internal Use. This statement requires
capitalization of certain costs of internal-use software. The Company adopted
this statement in January 1999, and it is not expected to have a material impact
on the financial statements.
In April 1998, the AICPA issued a new Statement of Position, Reporting on the
Costs of Start-up Activities. This statement requires that the costs of start-up
activities and organizational costs be expensed as incurred. Any of these costs
previously capitalized by a company must be written off in the year of adoption.
The Company adopted this statement in January 1999, and it is not expected to
have a material impact on the financial statements.
In December 1998, the Emerging Issues Task Force (EITF) of the FASB issued
EITF No. 98-10, Accounting for Contracts Involved in Energy Trading and Risk
Management Activities. The EITF requires that energy trading contracts must be
marked to market through the income statement, with gains and losses reflected
rather than revenues and purchased power. Energy trading contracts are defined
9
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 1998 Annual Report
as energy contracts entered into with the objective of generating profits on or
from exposure to shifts or changes in market prices. The Company adopted the
required accounting in January 1999, and it is not expected to have a material
impact on the financial statements.
FINANCIAL CONDITION
Plant Additions
In 1998 gross utility plant additions were $499 million. These additions were
primarily related to transmission and distribution facilities and to the
purchase of nuclear fuel. The funds needed for gross property additions are
currently provided from operations. The Statements of Cash Flows provide
additional details.
Financing Activities
In 1998 the Company continued to lower its financing costs by refinancing
higher-cost issues. New issues during 1996 through 1998 totaled $1.6 billion and
retirement or repayment of securities totaled $2.0 billion. Composite financing
rates for long-term debt and preferred stock for the years 1996 through 1998, as
of year-end, were as follows:
1998 1997 1996
----------------------------------
Composite interest rate
on long-term debt 5.64% 6.11% 6.39%
Composite preferred
stock dividend rate 5.52 5.18 6.34
- ------------------------------------------------------------------
Subsidiaries of the Company have issued mandatorily redeemable preferred
securities. See Note 9 to the financial statements under "Preferred Securities"
for additional information.
Liquidity and Capital Requirements
Cash provided from operations increased by $30 million in 1998, primarily due to
higher retail revenues.
The Company estimates that construction expenditures for the years 1999
through 2001 will total $755 million, $734 million and $829 million,
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 and preferred stock are expected to total $601
million during 1999 through 2001.
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 $24 million in 1999 and
increases to $30 million in 2000 and 2001. 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, 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 1999. 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 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.
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.
10
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 1998 Annual Report
Environmental Issues
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 will be 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 could use emission
allowances, increase fuel switching, and/or install flue gas desulfurization
equipment at selected plants. Also, equipment to control nitrogen oxide
emissions will be installed on additional system fossil-fired units as necessary
to meet Phase II limits and ozone non-attainment requirements for metropolitan
Atlanta through 2000. Georgia Power's current compliance strategy for Phase II
and ozone non-attainment could require total estimated construction expenditures
of approximately $39 million, of which $14 million remains to be spent as of
December 31, 1998.
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.
In July 1997, the Environmental Protection Agency (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 rules to the states for implementation.
The states have one year to adopt and implement the new rules. The final rules
affect 22 states including Georgia. The EPA rules are being challenged in the
courts by several states and industry groups. Implementation of the final state
rules could require substantial further reductions in nitrogen oxide emissions
from fossil-fired generating facilities and other industry in these states.
Implementation of the standards could result in significant additional
compliance costs and capital expenditures that cannot be determined until the
results of legal challenges are known and the states have adopted their final
rules.
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 new standards will depend on the
development and implementation of applicable regulations.
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 $6 million, $4
million and $2 million, in 1998, 1997 and 1996, 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 "Certain 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.
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.
11
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 1998 Annual Report
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 1998 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; Year 2000
issues; 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.
12
STATEMENTS OF INCOME
For the Years Ended December 31, 1998, 1997, and 1996
Georgia Power Company 1998 Annual Report
===============================================================================================================================
1998 1997 1996
- -------------------------------------------------------------------------------------------------------------------------------
(in thousands)
Operating Revenues:
Revenues $ 4,656,647 $ 4,347,009 $ 4,380,893
Revenues from affiliates 81,606 38,708 35,886
- -------------------------------------------------------------------------------------------------------------------------------
Total operating revenues 4,738,253 4,385,717 4,416,779
- -------------------------------------------------------------------------------------------------------------------------------
Operating Expenses:
Operation--
Fuel 917,119 857,269 835,194
Purchased power from non-affiliates 229,960 143,409 157,308
Purchased power from affiliates 161,003 177,240 229,324
Provision for separation benefits 2,369 5,459 39,099
Other 817,220 696,700 741,383
Maintenance 358,218 317,199 315,934
Depreciation and amortization 763,390 572,640 432,940
Amortization of deferred Plant Vogtle costs (Note 1) 50,412 120,577 136,650
Write-down of Rocky Mountain plant (Note 3) 33,536 - -
Taxes other than income taxes 204,623 207,192 207,098
Federal and state income taxes 406,983 426,918 435,904
- -------------------------------------------------------------------------------------------------------------------------------
Total operating expenses 3,944,833 3,524,603 3,530,834
- -------------------------------------------------------------------------------------------------------------------------------
Operating Income 793,420 861,114 885,945
Other Income (Expense):
Allowance for equity funds used during construction 3,235 6,012 3,144
Equity in earnings of unconsolidated subsidiary (Note 4) 3,735 4,266 3,851
Interest income (Note 3) 79,578 10,581 5,333
Other, net (41,512) (35,834) (43,502)
Income taxes applicable to other income 8,351 31,763 18,581
- -------------------------------------------------------------------------------------------------------------------------------
Income Before Interest and Other Charges 846,807 877,902 873,352
- -------------------------------------------------------------------------------------------------------------------------------
Interest and Other Charges:
Interest on long-term debt 180,746 194,344 207,851
Allowance for debt funds used during construction (7,117) (8,962) (11,416)
Interest on interim obligations 12,213 7,795 15,478
Amortization of debt discount, premium and expense, net 13,366 14,179 14,790
Other interest charges 17,105 10,254 6,338
Distributions on preferred securities of subsidiary companies 54,327 47,369 14,958
- -------------------------------------------------------------------------------------------------------------------------------
Interest and other charges, net 270,640 264,979 247,999
- -------------------------------------------------------------------------------------------------------------------------------
Net Income 576,167 612,923 625,353
Dividends on Preferred Stock 5,939 18,927 45,026
- -------------------------------------------------------------------------------------------------------------------------------
Net Income After Dividends on Preferred Stock $ 570,228 $ 593,996 $ 580,327
===============================================================================================================================
The accompanying notes are an integral part of these statements.
13
STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 1998, 1997, and 1996
Georgia Power Company 1998 Annual Report
==========================================================================================================================
1998 1997 1996
- --------------------------------------------------------------------------------------------------------------------------
(in thousands)
Operating Activities:
Net income $ 576,167 $ 612,923 $ 625,353
Adjustments to reconcile net income to net
cash provided from operating activities --
Depreciation and amortization 867,637 674,286 521,086
Deferred income taxes and investment tax credits, net (93,005) (21,425) 35,700
Allowance for equity funds used during construction (3,235) (6,012) (3,144)
Amortization of deferred Plant Vogtle costs 50,412 120,577 136,650
Other, net (6,546) 2,076 45,255
Changes in certain current assets and liabilities --
Receivables, net (25,453) 13,387 9,421
Inventories (11,156) 39,748 55,753
Payables 47,862 (10,007) (35,651)
Taxes accrued 22,139 (3,596) 11,766
Energy cost recovery, retail (7,649) (20,103) 679
Other (15,142) (30,026) (15,880)
- --------------------------------------------------------------------------------------------------------------------------
Net cash provided from operating activities 1,402,031 1,371,828 1,386,988
- --------------------------------------------------------------------------------------------------------------------------
Investing Activities:
Gross property additions (499,053) (475,921) (428,220)
Other 67,031 16,223 (13,149)
- --------------------------------------------------------------------------------------------------------------------------
Net cash used for investing activities (432,022) (459,698) (441,369)
- --------------------------------------------------------------------------------------------------------------------------
Financing Activities:
Proceeds --
Preferred securities - 364,250 225,000
First mortgage bonds - - 10,000
Pollution control bonds 89,990 284,700 112,825
Senior notes 495,000 - -
Retirements --
Preferred stock (106,064) (356,392) (179,148)
First mortgage bonds (558,250) (60,258) (210,860)
Pollution control bonds (89,990) (284,700) (119,665)
Interim obligations, net (25,378) (64,266) 30,166
Special deposits -- redemption funds - 44,454 (44,454)
Capital distribution to parent company (270,000) (205,000) (250,000)
Payment of preferred stock dividends (9,137) (26,917) (46,911)
Payment of common stock dividends (536,600) (520,000) (475,500)
Miscellaneous (26,641) (20,024) (10,646)
- --------------------------------------------------------------------------------------------------------------------------
Net cash used for financing activities (1,037,070) (844,153) (959,193)
- --------------------------------------------------------------------------------------------------------------------------
Net Change in Cash and Cash Equivalents (67,061) 67,977 (13,574)
Cash and Cash Equivalents at Beginning of Year 83,333 15,356 28,930
- --------------------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of Year $ 16,272 $ 83,333 $ 15,356
==========================================================================================================================
Supplemental Cash Flow Information:
Cash paid during the year for --
Interest (net of amount capitalized) $ 269,524 $ 258,298 $ 249,434
Income taxes (net of refunds) 480,318 427,596 373,886
- --------------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these statements.
14
BALANCE SHEETS
At December 31, 1998 and 1997
Georgia Power Company 1998 Annual Report
================================================================================================================================
ASSETS 1998 1997
- --------------------------------------------------------------------------------------------------------------------------------
(in thousands)
Utility Plant:
Plant in service $ 15,441,146 $ 15,082,570
Less accumulated provision for depreciation 6,109,331 5,319,680
- --------------------------------------------------------------------------------------------------------------------------------
9,331,815 9,762,890
Nuclear fuel, at amortized cost 121,169 126,882
Construction work in progress (Note 4) 189,849 214,128
- --------------------------------------------------------------------------------------------------------------------------------
Total 9,642,833 10,103,900
- --------------------------------------------------------------------------------------------------------------------------------
Other Property and Investments:
Southern Electric Generating Company, at equity (Note 4) 24,360 24,973
Nuclear decommissioning trusts, at market 284,536 194,417
Miscellaneous 34,781 87,907
- --------------------------------------------------------------------------------------------------------------------------------
Total 343,677 307,297
- --------------------------------------------------------------------------------------------------------------------------------
Current Assets:
Cash and cash equivalents 16,272 83,333
Receivables--
Customer accounts receivable 439,420 385,844
Other accounts and notes receivable 99,574 110,278
Affiliated companies 16,817 20,333
Accumulated provision for uncollectible accounts (5,500) (3,000)
Fossil fuel stock, at average cost 104,133 96,067
Materials and supplies, at average cost 243,477 240,387
Prepayments 29,670 27,503
Vacation pay deferred 43,610 40,996
- --------------------------------------------------------------------------------------------------------------------------------
Total 987,473 1,001,741
- --------------------------------------------------------------------------------------------------------------------------------
Deferred Charges and Other Assets:
Deferred charges related to income taxes (Note 8) 604,488 688,472
Deferred Plant Vogtle costs (Note 1) - 50,412
Premium on reacquired debt, being amortized 173,858 166,609
Prepaid pension costs 103,606 67,777
Debt expense, being amortized 51,261 40,927
Miscellaneous 126,422 146,593
- --------------------------------------------------------------------------------------------------------------------------------
Total 1,059,635 1,160,790
- --------------------------------------------------------------------------------------------------------------------------------
Total Assets $ 12,033,618 $ 12,573,728
================================================================================================================================
The accompanying notes are an integral part of these statements.
15
BALANCE SHEETS (continued)
At December 31, 1998 and 1997
Georgia Power Company 1998 Annual Report
=================================================================================================================================
CAPITALIZATION AND LIABILITIES 1998 1997
- --------------------------------------------------------------------------------------------------------------------------------
(in thousands)
Capitalization (See accompanying statements):
Common stock equity $ 3,784,172 $ 4,019,728
Preferred stock 15,527 157,247
Company obligated mandatorily redeemable preferred securities
of subsidiaries substantially all of whose assets are junior
subordinated debentures or notes (Note 9) 689,250 689,250
Long-term debt 2,744,362 2,982,835
- --------------------------------------------------------------------------------------------------------------------------------
Total 7,233,311 7,849,060
- --------------------------------------------------------------------------------------------------------------------------------
Current Liabilities:
Preferred stock due within one year (Note 9) 35,656 -
Long-term debt due within one year (Note 9) 399,429 220,855
Notes payable to banks (Note 9) 117,634 142,300
Commercial paper (Note 9) 223,218 223,930
Accounts payable--
Affiliated companies 75,774 71,373
Other 326,317 261,293
Customer deposits 69,584 68,618
Taxes accrued--
Federal and state income 15,801 4,480
Other 122,359 111,541
Interest accrued 60,187 72,437
Miscellaneous 100,793 105,683
- --------------------------------------------------------------------------------------------------------------------------------
Total 1,546,752 1,282,510
- --------------------------------------------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes (Note 8) 2,249,613 2,417,547
Accumulated deferred investment tax credits 381,914 397,202
Deferred credits related to income taxes (Note 8) 284,017 297,560
Employee benefits provisions 177,148 169,887
Miscellaneous 160,863 159,962
- --------------------------------------------------------------------------------------------------------------------------------
Total 3,253,555 3,442,158
- --------------------------------------------------------------------------------------------------------------------------------
Commitments and Contingent Matters (Notes 1 through 7)
Total Capitalization and Liabilities $ 12,033,618 $ 12,573,728
================================================================================================================================
The accompanying notes are an integral part of these statements.
16
STATEMENTS OF CAPITALIZATION
At December 31, 1998 and 1997
Georgia Power Company 1998 Annual Report
==================================================================================================================================
1998 1997 1998 1997
- -----------------------------------------------------------------------------------------------------------------------------------
(in thousands) (percent of total)
Common Stock Equity:
Common stock, without par value --
Authorized -- 15,000,000 shares
Outstanding -- 7,761,500 shares $ 344,250 $ 344,250
Paid-in capital 1,660,206 1,929,971
Premium on preferred stock 158 160
Retained earnings (See accompanying statement) (Note 9) 1,779,558 1,745,347
- -----------------------------------------------------------------------------------------------------------------------------------
Total common stock equity 3,784,172 4,019,728 52.3 % 51.2 %
- -----------------------------------------------------------------------------------------------------------------------------------
Cumulative Preferred Stock, without par value:
Authorized -- 55,000,000 shares
Outstanding -- 511,834 shares at December 31, 1998
Outstanding -- 4,719,226
shares at December 31, 1997
$100 stated value --
4.60% to 6.60% 51,183 52,355
Adjustable rate -- at January 1, 1998:
4.85% - 64,213
5.27% - 40,679
- --------------------------------------------------------------------------------------------------------------
Total cumulative preferred stock (annual dividend
requirement -- $2,827,000) 51,183 157,247
Less amount due within one year (Note 9) 35,656 -
- -----------------------------------------------------------------------------------------------------------------------------------
Cumulative preferred stock excluding amount due within one year 15,527 157,247 0.2 2.0
- -----------------------------------------------------------------------------------------------------------------------------------
Company Obligated Mandatorily
Redeemable Preferred Securities (Note 9):
$25 liquidation value -- 9% 100,000 100,000
$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
- -----------------------------------------------------------------------------------------------------------------------------------
Total (annual distribution requirement -- $54,404,000) 689,250 689,250 9.5 8.8
- -----------------------------------------------------------------------------------------------------------------------------------
Long-Term Debt:
First mortgage bonds --
Maturity Interest Rates
April 1, 1998 5 1/2% - 100,000
September 1, 1999 6 1/8% 195,000 195,000
March 1, 2000 6% 100,000 100,000
October 1, 2000 7% - 100,000
September 1, 2002 6 7/8% - 150,000
April 1, 2003 6 5/8% 200,000 200,000
August 1, 2003 6.35% 75,000 75,000
2004 through 2006 6.07% 10,000 10,000
2008 6 7/8% 50,000 50,000
2023 through 2025 7.55% to 7.95% 266,000 474,250
- ---------------------------------------------------------------------------------------------------------------
Total first mortgage bonds 896,000 1,454,250
- ---------------------------------------------------------------------------------------------------------------
Pollution control bonds -- (Note 9)
Maturity Interest Rates
-------- --------------
2000 4.375% 50,000 50,000
2004-2005 5% to 5.375% 57,000 103,790
2011 Variable (4.0% at 1/1/99) 10,450 10,450
2018 6% 4,600 26,700
2019-2023 5.75% to 6.35% 140,560 144,660
2022-2023 Variable (4.0% to 5.05% at 1/1/99) 64,500 64,500
2024-2025 5.4% to 6.75% 440,325 457,325
2024-2028 Variable (3.10% to 5.20% at 1/1/99) 619,055 529,065
2029-2033 Variable (3.25% to 5.15% at 1/1/99) 234,700 234,700
2034 Variable (3.25% at 1/1/99) 50,000 50,000
- ---------------------------------------------------------------------------------------------------------------
Total pollution control bonds 1,671,190 1,671,190
- ---------------------------------------------------------------------------------------------------------------
17
STATEMENTS OF CAPITALIZATION (continued)
At December 31, 1998 and 1997
Georgia Power Company 1998 Annual Report
===================================================================================================================================
1998 1997 1998 1997
- -----------------------------------------------------------------------------------------------------------------------------------
(in thousands) (percent of total)
Senior notes -- (Note 9)
Maturity Interest Rates
-------- --------------
December 1, 2005 5.50% 150,000 -
December 31, 2038 6.60% 200,000 -
December 31, 2047 6.875% 145,000 -
- ---------------------------------------------------------------------------------------------------------------
Total senior notes 495,000 -
- ---------------------------------------------------------------------------------------------------------------
Other long-term debt (Note 9) 86,280 86,675
Unamortized debt discount, net (4,679) (8,425)
- ---------------------------------------------------------------------------------------------------------------
Total long-term debt (annual interest
requirement -- $177,628,000) 3,143,791 3,203,690
Less amount due within one year (Note 9) 399,429 220,855
- -----------------------------------------------------------------------------------------------------------------------------------
Long-term debt excluding amount due within one year 2,744,362 2,982,835 38.0 38.0
- -----------------------------------------------------------------------------------------------------------------------------------
Total Capitalization $ 7,233,311 $ 7,849,060 100.0 % 100.0 %
===================================================================================================================================
The accompanying notes are an integral part of these statements.
18
STATEMENTS OF RETAINED EARNINGS
For the Years Ended December 31, 1998, 1997, and 1996
Georgia Power Company 1998 Annual Report
==================================================================================================================================
1998 1997 1996
- ----------------------------------------------------------------------------------------------------------------------------------
(in thousands)
Balance at Beginning of Period $ 1,745,347 $ 1,674,774 $ 1,569,905
Net income after dividends on preferred stock 570,228 593,996 580,327
Cash dividends on common stock (536,600) (520,000) (475,500)
Preferred stock transactions, net 583 (3,423) 42
- ----------------------------------------------------------------------------------------------------------------------------------
Balance at End of Period (Note 9) $ 1,779,558 $ 1,745,347 $ 1,674,774
==================================================================================================================================
STATEMENTS OF PAID-IN CAPITAL
For the Years Ended December 31, 1998, 1997, and 1996
Georgia Power Company 1998 Annual Report
==================================================================================================================================
1998 1997 1996
- ----------------------------------------------------------------------------------------------------------------------------------
(in thousands)
Balance at Beginning of Period $ 1,929,971 $ 2,134,886 $ 2,384,444
Capital distribution to parent company (270,000) (205,000) (250,000)
Contributions to capital by parent company 235 85 442
- ----------------------------------------------------------------------------------------------------------------------------------
Balance at End of Period $ 1,660,206 $ 1,929,971 $ 2,134,886
==================================================================================================================================
The accompanying notes are an integral part of these statements.
19
NOTES TO FINANCIAL STATEMENTS
Georgia Power Company 1998 Annual Report
1. SUMMARY OF SIGNIFICANT ACCOUNTING
POLICIES
General
The Company is a wholly owned subsidiary of Southern Company, which is the
parent company of five operating companies, 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 operating companies (Alabama Power Company, Georgia
Power Company, Gulf Power Company, Mississippi Power Company, and Savannah
Electric and Power Company) provide electric service in four Southeastern
states. Contracts among the operating companies -- dealing with 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 Energy
designs, builds, owns, and operates power production and delivery facilities and
provides a broad range of energy related services in the United States and
international markets. Southern Nuclear provides services to Southern Company's
nuclear power plants. Southern Company Energy Solutions develops new business
opportunities related to energy products and services.
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.
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 to the Company
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. Regulatory assets and (liabilities)
reflected in the Company's Balance Sheets at December 31 relate to the
following:
1998 1997
----------------------
(in millions)
Deferred income taxes $ 604 $ 688
Deferred income tax credits (284) (298)
Premium on reacquired debt 174 167
Corporate building lease 53 52
Deferred Plant Vogtle costs - 50
Vacation pay 44 41
Postretirement benefits 36 38
Department of Energy assessments 26 29
Deferred nuclear outage costs 24 28
Demand-side program costs - 11
Other, net 12 10
- ---------------------------------------------------------------
Total $ 689 $ 816
===============================================================
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 net 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.
20
NOTES (continued)
Georgia Power Company 1998 Annual Report
Revenues and Fuel Costs
The Company currently operates as a vertically integrated utility providing
electricity to retail customers within its traditional service area located
within the state of Georgia, and to wholesale customers in the Southeast.
Revenues by type of service were as follows:
1998 1997 1996
--------------------------------
(in millions)
Retail $4,298 $3,978 $4,023
Non-affiliated wholesale 260 283 282
Other 99 86 76
- ---------------------------------------------------------------
Total $4,657 $4,347 $4,381
===============================================================
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, 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 1998, $76 million in 1997, and $78 million in 1996. 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 at Plant Hatch by as early as
1999 are in progress.
Also, the Energy Policy Act of 1992 required the establishment in 1993 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, 1998, to be approximately $24 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
3.2 percent in 1998 and 3.1 percent in 1997 and 1996. In addition, the Company
recorded accelerated depreciation of electric plant of $316 million in 1998,
$159 million in 1997, and $24 million in 1996. The amount of such charges in the
accumulated provision for depreciation is $505 million at December 31, 1998. See
Note 3 under "Retail Rate Order" 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.
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.
21
NOTES (continued)
Georgia Power Company 1998 Annual Report
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% 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 1998 and fund
balance as of December 31, 1998 were:
Plant Plant
Hatch Vogtle
- -------------------------------------------------------------
(in millions)
Amount expensed in 1998 $ 11 $ 9
- -------------------------------------------------------------
Accumulated provisions:
Balance in external trust funds $172 $112
Balance in internal reserves 19 12
- -------------------------------------------------------------
Total $191 $124
=============================================================
Effective January 1, 1999, the GPSC increased the annual provision for
decommissioning expenses to $26 million. 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% and an
estimated trust earnings rate of 6.5%. 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.
Plant Vogtle Phase-In Plans
In 1987 and 1989, the GPSC ordered that the allowed costs of Plant Vogtle, a
two-unit nuclear facility of which Georgia Power owns 45.7 percent, be phased
into rates. Pursuant to the orders, the Company recorded a deferred return under
phase-in plans until October 1991 when the allowed investment was fully
reflected in rates. In 1991, the GPSC levelized the remaining Plant Vogtle
declining capacity buyback expenses over a six-year period. In addition, the
Company deferred certain Plant Vogtle operating expenses and financing costs
under accounting orders issued by the GPSC. These GPSC orders provided for the
recovery of deferred costs within 10 years. Costs deferred under the 1987 order
and the levelized buybacks were fully recovered as of September 1997. Under a
December 18, 1998 retail rate order from the GPSC, the remaining deferred costs
were fully amortized to expense in December 1998. See Note 3 under "Retail Rate
Order" for additional information.
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
22
NOTES (continued)
Georgia Power Company 1998 Annual Report
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 1998, 1997 and 1996, the average AFUDC rates
were 6.71 percent, 7.60 percent and 6.59 percent, respectively. AFUDC, net of
taxes, as a percentage of net income after dividends on preferred stock, was
less than 2.0 percent for 1998, 1997, and 1996.
Utility Plant
Utility plant is stated at original cost, less regulatory disallowances.
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 charged to utility plant.
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, 1998 $3,058 $3,105
At December 31, 1997 3,125 3,170
Preferred securities:
At December 31, 1998 689 716
At December 31, 1997 689 720
- --------------------------------------------------------------
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 trusts to the
extent deductible under federal income tax regulations or to the extent required
by the GPSC and FERC. In 1998, the Company adopted FASB Statement No. 132,
Employers' Disclosure about Pensions and Other Postretirement Benefits. The
measurement date is September 30 of each year.
The weighted average rates assumed in the actuarial calculations for both
the pension and postretirement benefit plans were:
1998 1997
- -----------------------------------------------------------------
Discount 6.75% 7.50%
Annual salary increase 4.25 5.00
Expected long-term return on plan
assets 8.50 8.50
- -----------------------------------------------------------------
Pension Plan
Changes during the year in the projected benefit obligations and in the fair
value of plan assets were as follows:
Projected
Benefit Obligations
---------------------------
1998 1997
- ----------------------------------------------------------------
(in millions)
Balance at beginning of year $1,119 $1,172
Service cost 30 30
Interest cost 82 82
Benefits paid (55) (42)
Actuarial (gain) loss and
employee transfers 41 (123)
- ----------------------------------------------------------------
Balance at end of year $1,217 $1,119
================================================================
Plan Assets
---------------------------
1998 1997
- ----------------------------------------------------------------
(in millions)
Balance at beginning of year $1,931 $1,797
Actual return on plan assets 11 338
Benefits paid (55) (42)
Employee transfers (28) (162)
- ----------------------------------------------------------------
Balance at end of year $1,859 $1,931
================================================================
23
NOTES (continued)
Georgia Power Company 1998 Annual Report
The accrued pension costs recognized in the Balance Sheets were as
follows:
1998 1997
- ---------------------------------------------------------------
(in millions)
Funded status $ 642 $ 812
Unrecognized transition obligation (35) (39)
Unrecognized prior service cost 45 48
Unrecognized net actuarial gain (548) (753)
- ---------------------------------------------------------------
Prepaid asset recognized in the
Balance Sheets $ 104 $ 68
===============================================================
Components of the plans' net periodic cost were as follows:
1998 1997 1996
- ---------------------------------------------------------------
(in millions)
Service cost $ 30 $ 30 $ 35
Interest cost 82 82 86
Expected return on plan assets (127) (121) (124)
Recognized net actuarial gain (20) (18) (14)
Net amortization (1) (1) (2)
- ---------------------------------------------------------------
Net pension income $ (36) $ (28) $ (19)
===============================================================
Postretirement Benefits
Changes during the year in the projected benefit obligations and
in the fair value of plan assets were as follows:
Projected
Benefit Obligations
---------------------------
1998 1997
- ----------------------------------------------------------------
(in millions)
Balance at beginning of year $ 435 $ 430
Service cost 7 7
Interest cost 32 32
Benefits paid (16) (13)
Actuarial loss and employee
transfers 6 (21)
- ----------------------------------------------------------------
Balance at end of year $ 464 $ 435
================================================================
Plan Assets
---------------------------
1998 1997
- ----------------------------------------------------------------
(in millions)
Balance at beginning of year $122 $112
Actual return on plan assets 4 9
Employer contributions 40 14
Benefits paid (16) (13)
- ----------------------------------------------------------------
Balance at end of year $150 $122
================================================================
The accrued postretirement costs recognized in the Balance
Sheets were as follows:
1998 1997
- ---------------------------------------------------------------
(in millions)
Funded status $ (314) $ (313)
Unrecognized transition obligation 131 139
Unrecognized net actuarial loss 57 47
Fourth quarter contributions 19 29
- ---------------------------------------------------------------
Accrued liability recognized in the
Balance Sheets $ (107) $ (98)
===============================================================
Components of the plans' net periodic cost were as follows:
1998 1997 1996
- ---------------------------------------------------------------
(in millions)
Service cost $ 7 $ 7 $ 9
Interest cost 32 32 30
Expected return on plan assets (9) (7) (5)
Recognized net actuarial loss 1 1 2
Net amortization 9 9 9
- ---------------------------------------------------------------
Net postretirement cost $ 40 $ 42 $ 45
===============================================================
An additional assumption used in measuring the accumulated postretirement
benefit obligations was a weighted average medical care cost trend rate of 8.30
percent for 1998, decreasing gradually to 4.75 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,
1998 as follows:
1 Percent 1 Percent
Increase Decrease
- ---------------------------------------------------------------
(in millions)
Benefit obligation $ 38 $ (32)
Service and interest costs 3 (3)
===============================================================
3. REGULATORY AND LITIGATION MATTERS
Retail Rate Order
As required by the GPSC, the Company filed a general rate case in 1998. 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 will be decreased by $262 million on an annual basis effective
January 1, 1999, and by an additional $24 million effective January 1, 2000. The
24
NOTES (continued)
Georgia Power Company 1998 Annual Report
order further provides for $85 million in each year, plus up to $50 million of
any earnings in excess of 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 in excess of the 12.5 percent return will
be applied to rate reductions, with the remaining one-third retained by the
Company. 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.
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 in excess of 12.5 percent were used to
accelerate the amortization of regulatory assets or depreciation of electric
plant. The Company was required to absorb cost increases of approximately $29
million annually during the order's three-year operation, including $14 million
annually of accelerated depreciation of electric plant.
The Company's 1996 retail return on common equity was within the 10 percent
to 12.5 percent range. During 1998 and 1997, for earnings in excess of the 12.5
percent retail return, the Company recorded charges of $292 million and $135
million, respectively, that are presented in the financial statements as
depreciation expense of electric plant and as an addition to the accumulated
provision for depreciation.
FERC Review of Equity Returns
On September 21, 1998, the FERC entered separate orders affirming the outcome of
the administrative law judge's opinions in two proceedings in which the return
on common equity component of formula rates contained in substantially all of
the operating companies' wholesale power contracts was being challenged as
unreasonably high. These orders resulted in no change in the wholesale power
contracts that were the subject of such proceedings. The FERC also dismissed a
complaint filed by three customers under long-term power sales agreements
seeking to lower the equity return component in such agreements. These customers
have filed applications for rehearing regarding each FERC order. In response to
a requirement of the September 1998 FERC order, Southern Company filed a new
equity return component on the long-term power sales contracts, to be effective
January 5, 1999. The proposed equity return was lowered from 13.75 percent to
12.50 percent. If the filed return is approved, annual revenues will decrease by
approximately $1 million. The FERC placed the new rates into effect, subject to
refund. Also, this filing was consolidated with the new proceeding discussed
below.
On December 28, 1998, the FERC staff filed a motion asking the FERC to
initiate a new proceeding regarding the equity return and other issues involving
the Company's formula rate contracts. The motion was submitted pursuant to
review procedures applicable to theses contracts, and would be applicable to
billings under such contracts on and after January 1, 1999.
Rocky Mountain Plant Status
In its 1985 financing order, the GPSC concluded that completion of the Rocky
Mountain pumped storage hydroelectric plant in 1991, as then planned, was not
economically justifiable and reasonable and withheld authorization for the
Company to spend funds from approved securities issuances on that plant. In
1988, the Company and Oglethorpe Power Corporation (OPC) entered into a joint
ownership agreement for OPC to assume responsibility for the construction and
operation of the plant, as discussed in Note 6. In 1995, the plant went into
commercial operation.
In June 1996, the GPSC initiated a review of the 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. The
Company appealed the GPSC's order to the Superior Court of Fulton County,
Georgia. Under the rate order approved by the GPSC on December 18, 1998, the
Company voluntarily dismissed the appeal. As a result, in December 1998, the
Company 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.
25
NOTES (continued)
Georgia Power Company 1998 Annual Report
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.
Demand-Side Conservation Programs
In August 1995, the GPSC ordered the Company to discontinue its current
demand-side conservation programs by the end of 1995. Rate riders previously
approved by the GPSC for recovery of the Company's costs incurred in connection
with these programs remained in effect until January 1998 when costs deferred
were fully collected.
Under a GPSC accounting order approved February 16, 1996, the Company
recognized approximately $29 million of deferred program costs over a three-year
period ending December 1998, which were not recovered through the riders.
Certain Environmental Contingencies
In January 1995, the Company and four other unrelated entities were notified by
the EPA that they have been designated as potentially responsible parties under
the Comprehensive Environmental Response, Compensation and Liability Act with
respect to a site in Brunswick, Georgia. As of December 31, 1998, 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 26 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 nine electrical substations on the list at a cumulative cost of
approximately $3 million. The State has removed from the list one power
generation facility following the assessment which indicated no remediation was
necessary. In addition, the Company has recognized approximately $23 million in
cumulative expenses through December 31, 1998 for the assessment of the
remaining sites on the list and the anticipated clean-up cost for 11 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 of Georgia determines whether remediation is required. If all
listed sites were required to be remediated, the Company could incur expenses of
up to approximately $10 million in additional clean-up costs and construction
expenditures of up to approximately $56 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.
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 will be
evaluated every three years. The performance standard is based on each unit's
capacity factor as compared to the average of all comparable U.S. nuclear units
operating at a capacity factor of 50 percent or higher during the three-year
period of evaluation. Depending on the performance of the units, the Company
could receive a monetary award or penalty under the performance standards
criteria.
The first evaluation was conducted in 1993 for performance during the
1990-92 period. The GPSC approved a performance award of approximately $8.5
million for the Company. This award was collected through the retail fuel cost
recovery provision and recognized in income over a 36-month period which ended
in October 1996. In January 1997, the GPSC approved a performance award of
approximately $11.7 million for performance during the 1993-95 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 1997.
26
NOTES (continued)
Georgia Power Company 1998 Annual Report
4. COMMITMENTS
Construction Program
While the Company has no traditional baseload generating plants under
construction, the construction of eight combustion turbine peaking units is
planned to be completed by 2000. 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 $755 million in 1999, $734 million in 2000, and $829 million
in 2001.
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,
1998 were as follows:
Minimum
Year Obligations
----------------------
(in millions)
1999 $ 642
2000 545
2001 483
2002 414
2003 366
2004 and beyond 719
- ----------------------------------------------------------------
Total minimum obligations $3,169
================================================================
Additional commitments for coal and for nuclear fuel will be required in the
future to supply the Company's fuel needs.
Purchased Power Commitments
In connection with the joint ownership arrangement for Plant Vogtle, discussed
in Note 6, the Company has made commitments to purchase portions of OPC's and
the Municipal Electric Authority of Georgia's (MEAG's) capacity and energy from
this plant. Declining commitments were in effect during periods of up to seven
years following commercial operation and ended in 1996. In addition, 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 $56 million, $54 million, and $68 million in
1998, 1997, and 1996, respectively. The current projected Plant Vogtle capacity
payments are:
Year Amounts
----------------------
(in millions)
1999 $ 59
2000 62
2001 61
2002 60
2003 60
2004 and beyond 711
- ----------------------------------------------------------------
Total $ 1,013
================================================================
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 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
27
NOTES (continued)
Georgia Power Company 1998 Annual Report
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:
1998 1997 1996
---------------------------------
(in millions)
Energy $45 $45 $47
Capacity 30 30 30
- --------------------------------------------------------------
Total $75 $75 $77
==============================================================
Kilowatt-hours 3,146 3,038 2,780
- --------------------------------------------------------------
At December 31, 1998, the capitalization of SEGCO consisted of $49 million
of equity and $70 million of long-term debt on which the annual interest
requirement is $4 million.
The Company has entered into other various long-term commitments for the
purchase of electricity. Total long-term obligations at December 31, 1998 were
as follows:
Year Amounts
----------------------
(in millions)
1999 $ 18
2000 21
2001 22
2002 23
2003 23
2004 and beyond 363
- ----------------------------------------------------------------
Total $ 470
================================================================
Operating Leases
The Company has entered into coal rail car rental agreements with various terms
and expiration dates. These expenses totaled $13 million for 1998, and $11
million each for 1997 and 1996. At December 31, 1998, estimated minimum rental
commitments for these noncancelable operating leases were as follows:
Year Amounts
----------------------
(in millions)
1999 $ 11
2000 11
2001 11
2002 12
2003 12
2004 and beyond 120
- ----------------------------------------------------------------
Total $177
================================================================
5. NUCLEAR INSURANCE
Under the Price-Anderson Amendments Act of 1988, the Company maintains
agreements of indemnity with the NRC that, together with private insurance,
cover third-party liability arising from any nuclear incident occurring at the
Company's nuclear power plants. The act provides funds up to $9.7 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 17 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 $25 million.
For all on-site property damage insurance policies for commercial nuclear
28
NOTES (continued)
Georgia Power Company 1998 Annual Report
power plants, the NRC requires that the proceeds of such policies issued or
renewed on or after April 2, 1991, shall be dedicated first for the sole purpose
of placing the reactor in a safe and stable condition after an accident. Any
remaining proceeds are to be applied next toward the costs of decontamination
and debris removal operations ordered by the NRC, and any further remaining
proceeds are to be paid either to the Company or to its bond trustees as may be
appropriate under the policies and applicable trust indentures.
All retrospective assessments, whether generated for liability, property or
replacement power, may be subject to applicable state premium taxes.
6. FACILITY SALES AND JOINT OWNERSHIP
AGREEMENTS
The Company has sold undivided interests in plants Hatch, Wansley, Vogtle, and
Scherer Units 1 and 2 to OPC, an electric membership generation and transmission
corporation; MEAG, a public corporation and an instrumentality of the state of
Georgia; and the City of Dalton, Georgia. The Company has sold an interest in
Plant Scherer Unit 3 to Gulf Power Company, an affiliate. Additionally, the
Company has sold 76.4 percent of Plant Scherer Unit 4 to Florida Power & Light
Company (FP&L) and the remaining 23.6 percent to Jacksonville Electric Authority
(JEA). The Company has also sold transmission facilities to Georgia Transmission
Corporation (formerly OPC's transmission division), MEAG, and the City of
Dalton.
Except as otherwise noted, the Company has contracted to operate and
maintain all jointly owned facilities. The Company includes its proportionate
share of plant operating expenses in the corresponding operating expenses in the
Statements of Income.
The Company owns 25.4 percent of the Rocky Mountain pumped storage
hydroelectric plant. OPC owns the remainder, and is the operator of the plant.
The Company owns six of eight 80 megawatt combustion turbine generating units
and 75 percent of the related common facilities at Plant McIntosh. Savannah
Electric and Power Company, an affiliate, owns the remainder and operates the
plant. The Company and Florida Power Corporation (FPC) jointly own a combustion
turbine unit at Intercession City, Florida, near Orlando. The unit began
commercial operation in January 1997, and is operated by FPC. The Company owns a
one-third interest in the unit, with use of 100 percent of the unit's capacity
from June through September. FPC has the capacity the remainder of the year.
At December 31, 1998, 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% $3,296* $1,514
Plant Hatch (nuclear) 50.1 840 538
Plant Wansley (coal) 53.5 298 141
Plant Scherer (coal)
Units 1 and 2 8.4 112 48
Unit 3 75.0 545 179
Plant McIntosh
Common Facilities 75.0 19 1
(combustion-turbine)
Rocky Mountain 25.4 169* 61
(pumped storage)
Intercession City 33.3 12 **
(combustion-turbine)
- --------------------------------------------------------------------
* Investment net of write-offs.
** Less than $1 million.
7. LONG-TERM POWER SALES AGREEMENTS
The Company and the operating subsidiaries 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)
1998 $ 32 162
1997 42 159
1996 41 173
-------------------------------------
Unit power from specific generating plants is being sold to FP&L, FPC, JEA,
and the City of Tallahassee, Florida. Under these agreements, the Company sold
approximately 162 megawatts of capacity in 1998 and is scheduled to sell
approximately 162 megawatts of capacity in 1999. In 2000, 129 megawatts will be
sold. After 2000, capacity sales will decline to approximately 105 megawatts --
unless reduced by FP&L, FPC, and JEA -- until the expiration of the contracts in
2010.
29
NOTES (continued)
Georgia Power Company 1998 Annual Report
8. INCOME TAXES
At December 31, 1998, tax-related regulatory assets were $604 million and
tax-related regulatory liabilities were $284 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:
1998 1997 1996
-------------------------------
Total provision for income taxes: (in millions)
Federal:
Currently payable $ 415 $352 $325
Deferred -
Current year 131 49 70
Reversal of prior years (218) (68) (41)
Deferred investment tax
credits 7 - -
- -----------------------------------------------------------------
335 333 354
- -----------------------------------------------------------------
State:
Currently payable 77 65 56
Deferred -
Current year 18 8 12
Reversal of prior years (31) (11) (5)
- -----------------------------------------------------------------
64 62 63
- -----------------------------------------------------------------
Total 399 395 417
- -----------------------------------------------------------------
Less:
Income taxes credited
to other income (8) (32) (19)
- -----------------------------------------------------------------
Total income taxes
charged to operations $ 407 $427 $436
=================================================================
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:
1998 1997
-------------------
(in millions)
Deferred tax liabilities:
Accelerated depreciation $1,670 $1,732
Property basis differences 854 968
Other 158 142
- ----------------------------------------------------------------
Total 2,682 2,842
- ----------------------------------------------------------------
Deferred tax assets:
Other property basis differences 211 216
Federal effect of state deferred taxes 95 99
Other deferred costs 96 83
Disallowed Plant Vogtle buybacks 23 23
Other 21 14
- ----------------------------------------------------------------
Total 446 435
- ----------------------------------------------------------------
Net deferred tax liabilities 2,236 2,407
Portion included in current assets 13 11
- ----------------------------------------------------------------
Accumulated deferred income taxes
in the Balance Sheets $2,249 $2,418
================================================================
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 $22 million in 1998, $15 million in 1997, and $17 million in 1996.
At December 31, 1998, 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:
1998 1997 1996
--------------------------
Federal statutory rate 35% 35% 35%
State income tax, net of
federal deduction 4 4 4
Non-deductible book
depreciation 6 4 3
Other (4) (4) (2)
- ---------------------------------------------------------------
Effective income tax rate 41% 39% 40%
===============================================================
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. Tax
benefits from losses of the parent company are allocated to each subsidiary
based on the ratio of taxable income to total consolidated taxable income.
30
NOTES (continued)
Georgia Power Company 1998 Annual Report
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,
1998, $883 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
In December 1994, Georgia Power Capital, L.P., of which the Company is the sole
general partner, issued $100 million of 9 percent mandatorily redeemable
preferred securities. Substantially all of the assets of Georgia Power Capital,
L.P., are $103 million aggregate principal amount of Georgia Power's 9 percent
Junior Subordinated Deferrable Interest Debentures due December 19, 2024.
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
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. In February 1999, the Company issued an additional $200 million of
mandatorily redeemable preferred securities (Trust IV), bearing interest at 6.85
percent. The associated junior subordinated notes will be due March 31, 2029.
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 Georgia Power Capital, L.P.'s and the Trusts'
payment obligations with respect to the preferred securities.
Georgia Power Capital, L.P., and the Trusts are subsidiaries of the Company,
and accordingly are consolidated in the Company's financial statements.
Pollution Control Bonds
The Company has incurred obligations in connection with the sale by public
authorities of tax-exempt pollution control revenue bonds. The Company has
authenticated and delivered to trustees an aggregate of $1.2 billion of its
first mortgage bonds, which are pledged as security for its obligations under
pollution control revenue contracts. No interest on these first mortgage bonds
is payable unless and until a default occurs on the installment purchase or loan
agreements.
Senior Notes
In January, November, and December 1998, the Company issued 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 1999, the Company had unused credit arrangements with banks
totaling $1.3 billion, of which $722 million expires at various times during
1999, $30 million expires at May 1, 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 23, 1999 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.
31
NOTES (continued)
Georgia Power Company 1998 Annual Report
Approximately $162 million of the $722 million arrangements expiring during
1999 allow for two-year term loans executable upon expiration date of the credit
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.
The $1.3 billion in unused credit arrangements provide liquidity support to
the Company's variable rate pollution control bonds. The amount of variable rate
pollution control bonds outstanding as of December 31, 1998 was $979 million.
In addition, the Company borrows under uncommitted lines of credit with
banks and through a $225 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 1998.
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, 1998 and 1997, 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, 1998 and 1997, the interest and lease amortization deferred on
the Balance Sheets are $53 million and $52 million, respectively.
Assets Subject to Lien
The Company's mortgage dated as of March 1, 1941, as amended and supplemented,
securing the first mortgage bonds issued by the Company, constitutes a direct
lien on substantially all of the Company's fixed property and franchises.
Securities Due Within One Year
A summary of the improvement fund requirements and scheduled maturities and
redemptions of securities due within one year at December 31 is as follows:
1998 1997
-------------------
(in millions)
Bond improvement fund requirements $ 9 $ 15
Less:
Portion to be satisfied by certifying
property additions - -
- ----------------------------------------------------------------
Cash requirements 9 15
First mortgage bond maturities
and redemptions 390 205
- ----------------------------------------------------------------
Total long-term debt 399 220
Preferred stock 36 -
- ----------------------------------------------------------------
Total $435 $220
================================================================
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. The 1999
requirement was met in the first quarter of the year by depositing cash with the
trustee. These funds were used to redeem first mortgage bonds.
Redemption of Securities
The Company plans to continue 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.
32
NOTES (continued)
Georgia Power Company 1998 Annual Report
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 1998 and 1997 is as follows:
Net Income
After
Dividends on
Operating Operating Preferred Stock
Quarter Ended Revenues Income
- ---------------------------------------------------------------------
(in millions)
--------------------------------------------
March 1998 $ 984 $177 $ 106
June 1998 1,226 188 137
September 1998 1,530 325 255
December 1998 998 104 72
March 1997 $ 959 $180 $ 106
June 1997 1,015 205 131
September 1997 1,407 317 257
December 1997 1,005 159 100
- ---------------------------------------------------------------------
Earnings in the fourth quarter of 1998, compared to the fourth quarter of
1997, decreased primarily as a result of the December 1998 Rocky Mountain
write-off.
The Company's business is influenced by seasonal weather conditions.
33
SELECTED FINANCIAL AND OPERATING DATA
Georgia Power Company 1998 Annual Report
===============================================================================================================================
1998 1997 1996
- -------------------------------------------------------------------------------------------------------------------------------
Operating Revenues (in thousands) $4,738,253 $4,385,717 $4,416,779
Net Income after Dividends
on Preferred Stock (in thousands) $570,228 $593,996 $580,327
Cash Dividends on Common Stock (in thousands) $536,600 $520,000 $475,500
Return on Average Common Equity (percent) 14.61 14.53 13.73
Total Assets (in thousands) $12,033,618 $12,573,728 $13,006,635
Gross Property Additions (in thousands) $499,053 $475,921 $428,220
- -------------------------------------------------------------------------------------------------------------------------------
Capitalization (in thousands):
Common stock equity $3,784,172 $4,019,728 $4,154,281
Preferred stock 15,527 157,247 464,611
Preferred stock subject to mandatory redemption - - -
Company obligated mandatorily redeemable preferred securities 689,250 689,250 325,000
Long-term debt 2,744,362 2,982,835 3,200,419
- -------------------------------------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) $7,233,311 $7,849,060 $8,144,311
===============================================================================================================================
Capitalization Ratios (percent):
Common stock equity 52.3 51.2 51.0
Preferred stock 0.2 2.0 5.7
Company obligated mandatorily redeemable preferred securities 9.5 8.8 4.0
Long-term debt 38.0 38.0 39.3
- -------------------------------------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) 100.0 100.0 100.0
===============================================================================================================================
First Mortgage Bonds (in thousands):
Issued - - 10,000
Retired 558,250 60,258 210,860
Preferred Stock (in thousands):
Issued - - -
Retired 106,064 356,392 179,148
Senior Notes (in thousands):
Issued 495,000 - -
Company Obligated Mandatorily Redeemable
Preferred Securities (in thousands):
Issued - 364,250 225,000
- -------------------------------------------------------------------------------------------------------------------------------
Security Ratings:
First Mortgage Bonds -
Moody's A1 A1 A1
Standard and Poor's A+ A+ A+
Duff & Phelps AA- AA- AA-
Preferred Stock -
Moody's a2 a2 a2
Standard and Poor's A A A
Duff & Phelps A+ A+ A+
Unsecured Long-Term Debt -
Moody's A2 A2 A2
Standard and Poor's A A A
Duff & Phelps A+ A+ A+
- -------------------------------------------------------------------------------------------------------------------------------
Customers (year-end):
Residential 1,596,488 1,561,675 1,531,453
Commercial 221,180 211,672 205,087
Industrial 9,485 9,988 10,424
Other 3,034 2,748 2,645
- -------------------------------------------------------------------------------------------------------------------------------
Total 1,830,187 1,786,083 1,749,609
===============================================================================================================================
Employees (year-end) 8,371 8,354 * 10,346
*In 1997 Georgia Power Company transferred 1,855 employees to Southern Nuclearompany.
34
SELECTED FINANCIAL AND OPERATING DATA (continued)
Georgia Power Company 1998 Annual Report
=======================================================================================================================------------
1995 1994 1993 1992
- -----------------------------------------------------------------------------------------------------------------------------------
Operating Revenues (in thousands) $4,405,338 $4,162,403 $4,451,181 $4,297,436
Net Income after Dividends
on Preferred Stock (in thousands) $608,862 $525,544 $569,853 $520,538
Cash Dividends on Common Stock (in thousands) $451,500 $429,300 $402,400 $384,000
Return on Average Common Equity (percent) 14.43 12.84 14.37 13.60
Total Assets (in thousands) $13,470,275 $13,712,658 $13,736,110 $10,964,442
Gross Property Additions (in thousands) $480,449 $638,426 $674,432 $508,444
- -----------------------------------------------------------------------------------------------------------------------------------
Capitalization (in thousands):
Common stock equity $4,299,012 $4,141,554 $4,045,458 $3,888,237
Preferred stock 692,787 692,787 692,787 692,792
Preferred stock subject to mandatory redemption - - - 6,250
Company obligated mandatorily redeemable preferred securities 100,000 100,000 - -
Long-term debt 3,315,460 3,757,823 4,031,387 4,131,016
- -----------------------------------------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) $8,407,259 $8,692,164 $8,769,632 $8,718,295
===================================================================================================================================
Capitalization Ratios (percent):
Common stock equity 51.1 47.6 46.1 44.6
Preferred stock 8.2 8.0 7.9 8.0
Company obligated mandatorily redeemable preferred securities 1.2 1.2 - -
Long-term debt 39.5 43.2 46.0 47.4
- -----------------------------------------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) 100.0 100.0 100.0 100.0
===================================================================================================================================
First Mortgage Bonds (in thousands):
Issued 75,000 - 1,135,000 975,000
Retired 505,789 133,559 1,337,822 1,381,300
Preferred Stock (in thousands):
Issued - - 175,000 195,000
Retired - - 245,005 165,004
Senior Notes (in thousands):
Issued - - - -
Company Obligated Mandatorily Redeemable
Preferred Securities (in thousands):
Issued - 100,000 - -
- -----------------------------------------------------------------------------------------------------------------------------------
Security Ratings:
First Mortgage Bonds -
Moody's A1 A2 A3 A3
Standard and Poor's A+ A A- A-
Duff & Phelps AA- A+ A+ A-
Preferred Stock -
Moody's a2 a3 baa1 baa1
Standard and Poor's A A- BBB+ BBB+
Duff & Phelps A A- A- BBB
Unsecured Long-Term Debt -
Moody's A2 A3 Baa1 Baa1
Standard and Poor's A A- BBB+ BBB+
Duff & Phelps A+ A A BBB+
- -----------------------------------------------------------------------------------------------------------------------------------
Customers (year-end):
Residential 1,500,024 1,466,382 1,441,972 1,421,175
Commercial 198,624 193,648 188,820 183,784
Industrial 10,796 10,976 11,217 11,479
Other 2,568 2,426 2,322 2,269
- -----------------------------------------------------------------------------------------------------------------------------------
Total 1,712,012 1,673,432 1,644,331 1,618,707
===================================================================================================================================
Employees (year-end) 11,061 11,765 12,528 12,600
35A
SELECTED FINANCIAL AND OPERATING DATA (continued)
Georgia Power Company 1998 Annual Report
=================================================================================================================================
1991 1990 1989 1988
- ---------------------------------------------------------------------------------------------------------------------------------
Operating Revenues (in thousands) $4,301,428 $4,445,809 $4,145,240 $3,897,479
Net Income after Dividends
on Preferred Stock (in thousands) $474,855 $208,066 $449,099 $479,532
Cash Dividends on Common Stock (in thousands) $375,200 $389,600 $394,500 $386,600
Return on Average Common Equity (percent) 12.76 5.52 11.72 13.06
Total Assets (in thousands) $10,842,538 $11,176,619 $11,372,346 $11,130,539
Gross Property Additions (in thousands) $548,051 $558,727 $727,631 $929,019
- ---------------------------------------------------------------------------------------------------------------------------------
Capitalization (in thousands):
Common stock equity $3,766,551 $3,673,913 $3,860,657 $3,806,070
Preferred stock 607,796 607,796 607,844 657,844
Preferred stock subject to mandatory redemption 118,750 125,000 155,000 162,500
Company obligated mandatorily redeemable preferred securities - - - -
Long-term debt 4,553,189 5,000,225 5,054,001 4,861,378
- ---------------------------------------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) $9,046,286 $9,406,934 $9,677,502 $9,487,792
=================================================================================================================================
Capitalization Ratios (percent):
Common stock equity 41.7 39.1 39.9 40.1
Preferred stock 8.0 7.8 7.9 8.6
Company obligated mandatorily redeemable preferred securities - - - -
Long-term debt 50.3 53.1 52.2 51.3
- ---------------------------------------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) 100.0 100.0 100.0 100.0
=================================================================================================================================
First Mortgage Bonds (in thousands):
Issued - 300,000 250,000 150,000
Retired 598,384 91,117 91,516 206,677
Preferred Stock (in thousands):
Issued 100,000 - - -
Retired 100,000 83,750 7,500 3,750
Senior Notes (in thousands):
Issued - - - -
Company Obligated Mandatorily Redeemable
Preferred Securities (in thousands):
Issued - - - -
- ---------------------------------------------------------------------------------------------------------------------------------
Security Ratings:
First Mortgage Bonds -
Moody's Baa1 Baa1 Baa2 Baa2
Standard and Poor's BBB+ BBB+ BBB+ BBB
Duff & Phelps BBB+ BBB BBB 9
Preferred Stock -
Moody's baa1 baa1 baa2 baa2
Standard and Poor's BBB BBB BBB BBB-
Duff & Phelps BBB- BBB- BBB- 10
Unsecured Long-Term Debt -
Moody's Baa2 Baa2 - Baa3
Standard and Poor's BBB+ BBB - BBB-
Duff & Phelps BBB+ - - 10
- ---------------------------------------------------------------------------------------------------------------------------------
Customers (year-end):
Residential 1,397,682 1,378,888 1,355,211 1,329,173
Commercial 179,933 178,391 177,814 174,147
Industrial 11,946 12,115 12,311 12,353
Other 2,190 2,114 2,050 1,993
- ---------------------------------------------------------------------------------------------------------------------------------
Total 1,591,751 1,571,508 1,547,386 1,517,666
=================================================================================================================================
Employees (year-end) 13,700 13,746 13,900 15,110
35B
SELECTED FINANCIAL AND OPERATING DATA (continued)
Georgia Power Company 1998 Annual Report
===============================================================================================================================
1998 1997 1996
- -------------------------------------------------------------------------------------------------------------------------------
Operating Revenues (in thousands):
Residential $1,486,699 $1,326,787 $1,371,033
Commercial 1,591,363 1,493,353 1,486,586
Industrial 1,170,881 1,110,311 1,118,633
Other 49,274 47,848 47,060
- -------------------------------------------------------------------------------------------------------------------------------
Total retail 4,298,217 3,978,299 4,023,312
Sales for resale - non-affiliates 259,234 282,365 281,580
Sales for resale - affiliates 81,606 38,708 35,886
- -------------------------------------------------------------------------------------------------------------------------------
Total revenues from sales of electricity 4,639,057 4,299,372 4,340,778
Other revenues 99,196 86,345 76,001
- -------------------------------------------------------------------------------------------------------------------------------
Total $4,738,253 $4,385,717 $4,416,779
===============================================================================================================================
Kilowatt-Hour Sales (in thousands):
Residential 19,481,486 17,295,022 17,826,451
Commercial 22,861,391 21,134,346 20,823,073
Industrial 27,283,147 26,701,685 26,191,831
Other 543,462 538,163 536,057
- -------------------------------------------------------------------------------------------------------------------------------
Total retail 70,169,486 65,669,216 65,377,412
Sales for resale - non-affiliates 6,438,891 6,795,300 7,868,342
Sales for resale - affiliates 2,038,400 1,706,699 1,180,207
- -------------------------------------------------------------------------------------------------------------------------------
Total 78,646,777 74,171,215 74,425,961
===============================================================================================================================
Average Revenue Per Kilowatt-Hour (cents):
Residential 7.63 7.67 7.69
Commercial 6.96 7.07 7.14
Industrial 4.29 4.16 4.27
Total retail 6.13 6.06 6.15
Sales for resale 4.02 3.78 3.51
Total sales 5.90 5.80 5.83
Residential Average Annual Kilowatt-Hour Use Per Customer 12,314 11,171 11,763
Residential Average Annual Revenue Per Customer $939.72 $857.01 $904.70
Plant Nameplate Capacity Ratings (year-end) (megawatts) 14,437 14,437 14,367
Maximum Peak-Hour Demand (megawatts):
Winter 11,959 10,407 10,410
Summer 13,923 13,153 12,914
Annual Load Factor (percent) 58.7 57.4 62.2
Plant Availability (percent):
Fossil-steam 86.0 85.8 85.2
Nuclear 91.6 88.8 89.3
- -------------------------------------------------------------------------------------------------------------------------------
Source of Energy Supply (percent):
Coal 62.3 64.3 60.4
Nuclear 18.3 18.8 18.2
Hydro 2.2 2.2 2.2
Oil and gas 2.2 0.6 0.5
Purchased power -
From non-affiliates 6.5 2.7 5.6
From affiliates 8.5 11.4 13.1
- -------------------------------------------------------------------------------------------------------------------------------
Total 100.0 100.0 100.0
===============================================================================================================================
Total Fuel Economy Data:
BTU per net kilowatt-hour generated 10,118 9,990 10,468
Cost of fuel per million BTU (cents) 134.62 132.61 128.72
Average cost of fuel per net kilowatt-hour generated (cents) 1.36 1.32 1.35
===============================================================================================================================
* Less than one-tenth of one percent.
36
SELECTED FINANCIAL AND OPERATING DATA (continued)
Georgia Power Company 1998 Annual Report
==========================================================================================================================
1995 1994 1993 1992
- --------------------------------------------------------------------------------------------------------------------------
Operating Revenues (in thousands):
Residential $1,337,060 $1,180,358 $1,291,035 $1,128,396
Commercial 1,449,108 1,367,315 1,354,130 1,285,681
Industrial 1,141,766 1,100,995 1,113,067 1,083,856
Other 44,255 42,983 41,399 39,504
- --------------------------------------------------------------------------------------------------------------------------
Total retail 3,972,189 3,691,651 3,799,631 3,537,437
Sales for resale - non-affiliates 290,302 351,591 534,370 640,308
Sales for resale - affiliates 76,906 60,899 61,668 67,835
- --------------------------------------------------------------------------------------------------------------------------
Total revenues from sales of electricity 4,339,397 4,104,141 4,395,669 4,245,580
Other revenues 65,941 58,262 55,512 51,856
- --------------------------------------------------------------------------------------------------------------------------
Total $4,405,338 $4,162,403 $4,451,181 $4,297,436
==========================================================================================================================
Kilowatt-Hour Sales (in thousands):
Residential 17,307,399 15,680,709 16,649,859 14,939,172
Commercial 19,844,999 18,738,461 18,278,508 17,260,614
Industrial 25,286,340 24,337,632 23,635,363 22,978,312
Other 493,720 484,009 460,801 436,144
- --------------------------------------------------------------------------------------------------------------------------
Total retail 62,932,458 59,240,811 59,024,531 55,614,242
Sales for resale - non-affiliates 6,591,841 7,968,475 14,307,030 15,870,222
Sales for resale - affiliates 2,738,947 3,056,050 3,027,733 3,320,060
- --------------------------------------------------------------------------------------------------------------------------
Total 72,263,246 70,265,336 76,359,294 74,804,524
==========================================================================================================================
Average Revenue Per Kilowatt-Hour (cents):
Residential 7.73 7.53 7.75 7.55
Commercial 7.30 7.30 7.41 7.45
Industrial 4.52 4.52 4.71 4.72
Total retail 6.31 6.23 6.44 6.36
Sales for resale 3.94 3.74 3.44 3.69
Total sales 6.00 5.84 5.76 5.68
Residential Average Annual Kilowatt-Hour Use Per Customer 11,654 10,766 11,630 10,603
Residential Average Annual Revenue Per Customer $900.28 $810.39 $901.79 $800.88
Plant Nameplate Capacity Ratings (year-end) (megawatts) 14,344 13,943 13,759 14,076
Maximum Peak-Hour Demand (megawatts):
Winter 9,819 10,509 9,067 8,938
Summer 12,828 11,758 12,573 11,448
Annual Load Factor (percent) 59.6 63.0 58.5 60.5
Plant Availability (percent):
Fossil-steam 85.8 83.1 85.9 86.6
Nuclear 91.8 88.4 85.5 87.7
- --------------------------------------------------------------------------------------------------------------------------
Source of Energy Supply (percent):
Coal 63.0 61.3 62.1 61.4
Nuclear 19.3 18.0 16.2 17.0
Hydro 2.5 2.6 2.3 2.5
Oil and gas 0.6 0.1 0.2 *
Purchased power -
From non-affiliates 7.7 9.7 10.2 12.2
From affiliates 6.9 8.3 9.0 6.9
- --------------------------------------------------------------------------------------------------------------------------
Total 100.0 100.0 100.0 100.0
==========================================================================================================================
Total Fuel Economy Data:
BTU per net kilowatt-hour generated 10,039 9,915 9,912 9,900
Cost of fuel per million BTU (cents) 143.85 145.33 153.62 153.08
Average cost of fuel per net kilowatt-hour generated (cents) 1.44 1.44 1.52 1.52
==========================================================================================================================
* Less than one-tenth of one percent.
37A
SELECTED FINANCIAL AND OPERATING DATA (continued)
Georgia Power Company 1998 Annual Report
===============================================================================================================================
1991 1990 1989 1988
- -------------------------------------------------------------------------------------------------------------------------------
Operating Revenues (in thousands):
Residential $1,111,358 $1,109,165 $1,022,781 $979,047
Commercial 1,243,067 1,218,441 1,143,727 1,054,995
Industrial 1,057,702 1,061,830 1,006,416 983,822
Other 37,861 36,773 34,775 31,743
- -------------------------------------------------------------------------------------------------------------------------------
Total retail 3,449,988 3,426,209 3,207,699 3,049,607
Sales for resale - non-affiliates 736,643 784,086 760,809 707,076
Sales for resale - affiliates 65,586 168,251 150,394 86,751
- -------------------------------------------------------------------------------------------------------------------------------
Total revenues from sales of electricity 4,252,217 4,378,546 4,118,902 3,843,434
Other revenues 49,211 67,263 26,338 54,045
- -------------------------------------------------------------------------------------------------------------------------------
Total $4,301,428 $4,445,809 $4,145,240 $3,897,479
===============================================================================================================================
Kilowatt-Hour Sales (in thousands):
Residential 14,815,089 14,771,648 14,134,195 13,800,038
Commercial 16,885,833 16,627,128 15,843,181 14,790,561
Industrial 22,298,062 22,126,604 21,801,404 21,412,845
Other 429,016 428,459 414,107 397,669
- -------------------------------------------------------------------------------------------------------------------------------
Total retail 54,428,000 53,953,839 52,192,887 50,401,113
Sales for resale - non-affiliates 18,719,924 20,158,681 20,479,412 18,544,705
Sales for resale - affiliates 3,885,892 8,272,528 7,489,948 3,327,814
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Total 77,033,816 82,385,048 80,162,247 72,273,632
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Average Revenue Per Kilowatt-Hour (cents):
Residential 7.50 7.51 7.24 7.09
Commercial 7.36 7.33 7.22 7.13
Industrial 4.74 4.80 4.62 4.59
Total retail 6.34 6.35 6.15 6.05
Sales for resale 3.55 3.35 3.26 3.63
Total sales 5.52 5.31 5.14 5.32
Residential Average Annual Kilowatt-Hour Use Per Customer 10,675 10,795 10,530 10,484
Residential Average Annual Revenue Per Customer $800.78 $810.56 $761.96 $743.82
Plant Nameplate Capacity Ratings (year-end) (megawatts) 14,076 14,366 14,366 13,018
Maximum Peak-Hour Demand (megawatts):
Winter 10,001 8,977 10,101 9,866
Summer 13,090 13,196 12,735 12,295
Annual Load Factor (percent) 55.2 55.5 56.3 59.1
Plant Availability (percent):
Fossil-steam 93.3 92.5 93.0 94.5
Nuclear 81.6 81.3 89.2 69.4
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Source of Energy Supply (percent):
Coal 63.6 65.1 64.0 72.0
Nuclear 15.3 13.7 14.1 9.6
Hydro 2.3 2.2 2.1 1.2
Oil and gas * 0.1 0.1 0.1
Purchased power -
From non-affiliates 10.3 11.0 10.2 8.2
From affiliates 8.5 7.9 9.5 8.9
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Total 100.0 100.0 100.0 100.0
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Total Fuel Economy Data:
BTU per net kilowatt-hour generated 9,960 9,939 10,020 9,969
Cost of fuel per million BTU (cents) 157.97 166.22 164.27 166.28
Average cost of fuel per net kilowatt-hour generated (cents) 1.57 1.65 1.65 1.66
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* Less than one-tenth of one percent.
37B