<PAGE> 1
SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
FORM 8-K
CURRENT REPORT
Pursuant to Section 13 or 15(d) of the
Securities Exchange Act of 1934
Date of Report (Date of earliest event reported) February 16, 1994
GEORGIA POWER COMPANY
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(Exact name of registrant as specified in its charter)
Georgia 1-6468 58-0257110
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(State or other jurisdiction (Commission (IRS Employer
of incorporation) File Number) Identification No.)
333 Piedmont Avenue, N.E., Atlanta, Georgia 30308
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(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code (404) 526-6526
--------------
N/A
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(Former name or former address, if changed since last report.)
<PAGE> 2
Item 7. Financial Statements, Pro Forma Financial Information and Exhibits.
<TABLE>
<S> <C> <C>
(c) Exhibits.
23 - Consent of Arthur Andersen & Co.
99 - Audited Financial Statements of Georgia Power Company as of December 31, 1993.
</TABLE>
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934,
the registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
GEORGIA POWER COMPANY
By /s/ Wayne Boston
--------------------------
Wayne Boston
Assistant Secretary
Date: March 1, 1994
<PAGE> 1
EXHIBIT 23
ARTHUR ANDERSEN & CO.
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the incorporation of
our report dated February 16, 1994, included in this Form 8-K, into Georgia
Power Company's previously filed Registration Statement File No. 33-49661.
/s/ Arthur Andersen & Co.
-------------------------
ARTHUR ANDERSEN & CO.
Atlanta, Georgia
March 1, 1994
<PAGE> 1
EXHIBIT 99
MANAGEMENT'S REPORT
Georgia Power Company 1993 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 five
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 the
financial position, results of operations and cash flows of Georgia Power
Company in conformity with generally accepted accounting principles. As
discussed in Note 4 to the financial statements, an uncertainty exists with
respect to the actions of regulators regarding recoverability of the Company's
investment in the Rocky Mountain pumped storage hydroelectric project. The
outcome of this uncertainty cannot be determined until regulatory proceedings
are concluded. Accordingly, no provision for any write-down of the costs
associated with the Rocky Mountain project resulting from the potential actions
of the Georgia Public Service Commission has been made in the accompanying
financial statements.
/s/ H. Allen Franklin /s/ Warren Y. Jobe
- --------------------- --------------------------
H. Allen Franklin Warren Y. Jobe
President and Chief Executive Vice President,
Executive Officer Treasurer and Chief
Financial Officer
1
<PAGE> 2
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
Georgia Power Company 1993 Annual Report
TO THE BOARD OF DIRECTORS
OF GEORGIA POWER COMPANY:
We have audited the accompanying balance sheets and statements of
capitalization of Georgia Power Company (a Georgia corporation) as of December
31, 1993 and 1992, 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, 1993. 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 10-30) referred to above
present fairly, in all material respects, the financial position of Georgia
Power Company as of December 31, 1993 and 1992, and the results of its
operations and its cash flows for the periods stated, in conformity with
generally accepted accounting principles.
As explained in Notes 2 and 7 to the financial statements, effective January
1, 1993, the Company changed its methods of accounting for postretirement
benefits other than pensions and for income taxes.
As more fully discussed in Note 4 to the financial statements, an uncertainty
exists with respect to the actions of the regulators regarding the
recoverability of the Company's investment in the Rocky Mountain pumped storage
hydroelectric project. The outcome of this uncertainty cannot be determined
until regulatory proceedings are concluded. Accordingly, no provision for any
write-down of the costs associated with the Rocky Mountain project resulting
from the potential actions of the Georgia Public Service Commission has been
made in the accompanying financial statements.
/s/ Arthur Andersen & Co.
Atlanta, Georgia
February 16, 1994
2
<PAGE> 3
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL
CONDITION
Georgia Power Company 1993 Annual Report
RESULTS OF OPERATIONS
EARNINGS
Georgia Power Company's 1993 earnings totaled $570 million, representing a $49
million (9.5 percent) increase over the prior year. This improvement is
primarily a result of higher retail revenues and lower financing costs. Also,
during the period, the Company had an $18 million after-tax gain on the sale of
a portion of Plant Scherer Unit 4. Higher retail revenues reflect growth in
energy sales of 6.1 percent from 1992 levels primarily due to exceptionally hot
summer weather during 1993. Interest expense and preferred stock dividends
decreased in 1993 due to the redemption and refinancing of higher-cost debt and
preferred stock. These positive events were partially offset by higher
operating expenses.
In comparing 1992 earnings to the prior year, it should be noted that 1991
earnings included two unusual items that significantly affect this comparison.
Earnings in 1991 were $89 million higher due to the completion of a settlement
agreement with Gulf States Utilities Company (Gulf States) related to power
sales contracts. This increase was partially offset by an after-tax charge of
$33 million in 1991 for a work force reduction program. A comparison of 1992
to 1991 -- excluding these unusual items -- would reflect a 1992 increase in
earnings of $102 million.
REVENUES
The following table summarizes the factors impacting operating revenues for the
1991-1993 period:
<TABLE>
Increase (Decrease)
From Prior Year
1993 1992 1991
(in millions)
<S> <C> <C> <C>
Retail -
Change in base rates $ - $ 95 $ 27
Sales growth 45 76 67
Weather 126 (58) (16)
Fuel cost recovery 76 (26) (54)
Demand-side option
programs 15 - -
Total retail 262 87 24
Sales for resale -
Non-affiliates (106) (96) (47)
Affiliates (6) 2 (103)
Total sales for resale (112) (94) (150)
Other operating revenues 4 3 (18)
Total operating revenues $ 154 $ (4) $ (144)
Percent change 3.6% (0.1)% (3.2)%
</TABLE>
Retail revenues of $3.8 billion in 1993 increased $262 million (7.4 percent)
over the prior year, compared with an increase of $87 million (2.5 percent) in
1992. The exceptionally hot weather during the summer of 1993 was the primary
factor affecting the increase in retail revenues over 1992. The increase in
retail revenues for 1992 was a result of higher retail rates and sales growth,
partially offset by mild weather and lower fuel revenues. 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 options programs generally represent the direct recovery of program
costs. See Note 3 to the financial statements for further information on these
programs.
Revenues from sales to non-affiliated utilities decreased in both 1993 and
1992. Contractual unit power sales to Florida utilities for 1993 and 1992 are
down compared with prior years, primarily due to scheduled reductions that
corresponded with the sales to these utilities of portions of Plant Scherer
Unit 4 in July 1991 and June
3
<PAGE> 4
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 1993 Annual Report
1993. Sales to municipalities and cooperatives increased slightly in 1993 due
to the hot summer weather. Generally, these sales have been decreasing as
these customers retain more of their own generation at facilities jointly owned
with the Company.
Revenues from sales to non-affiliated utilities outside the service area under
long-term contracts consist of capacity and energy components. Capacity
revenues reflect the recovery of fixed costs and a return on investment under
the contracts. Energy is generally sold at variable cost. The capacity and
energy components were as follows:
<TABLE>
<CAPTION>
1993 1992 1991
(in millions)
<S> <C> <C> <C>
Capacity $152 $233 $274
Energy 113 168 204
Total $265 $401 $478
</TABLE>
Revenues from sales to affiliated companies within the Southern electric
system will vary from year to year depending on demand and the availability and
cost of generating resources at each company. Sales to affiliated companies do
not have a significant impact on earnings.
Changes in revenues are a function of the amount of energy sold each year.
Kilowatt-hour (KWH) sales for 1993 and the percent change by year were as
follows:
<TABLE>
<CAPTION>
Percent Change
1993
KWH 1993 1992 1991
(in billions)
<S> <C> <C> <C> <C>
Residential 16.7 11.5% 0.8% 0.3%
Commercial 18.3 5.9 2.2 1.6
Industrial 23.6 2.9 3.1 0.8
Other 0.5 5.7 1.7 0.1
Total retail 59.1 6.1 2.2 0.9
Sales for resale -
Non-affiliates 14.3 (9.8) (15.2) (7.1)
Affiliates 3.0 (8.8) (14.6) (53.0)
Total sales for
resale 17.3 (9.7) (15.1) (20.5)
Total sales 76.4 2.1 (2.9) (6.5)
</TABLE>
The hot summer weather during 1993 contributed primarily to the sales growth
in the residential and commercial classes. Continued improvement in economic
conditions positively impacted sales growth in the commercial and industrial
classes. Residential energy sales growth in 1992 reflected mild weather.
Commercial and industrial sales growth in 1992 is attributable to improved
economic conditions.
The decrease in energy sales to non-affiliated utilities reflects scheduled
reductions in contractual power sales.
EXPENSES
Fuel expense increased 2.3 percent in 1993 due to higher generation, which was
partially offset by lower nuclear fuel costs. In 1992, fuel expense decreased
6.9 percent due to lower generation and lower fuel costs. Purchased power
expense has decreased significantly since 1991, reflecting declining
contractual capacity purchases from the co-owners of plants Vogtle and Scherer.
Purchased power expense decreased $88 million in 1993 and $43 million in 1992.
The declines in Plant Vogtle contractual capacity purchases did not have a
significant impact on earnings in 1993 or 1992 as these costs are being
levelized over six years under the terms of the 1991 Georgia Public Service
Commission (GPSC) retail rate order. The levelization is reflected in the
amortization of deferred Plant Vogtle expenses in the income statements. See
Note 3 to the financial statements for additional information.
Other Operation and Maintenance (O & M) expenses increased 9.0 percent in
1993 after remaining relatively flat in 1992. The increase in 1993 is
primarily the result of environmental remediation costs at various current and
former operating sites, the one- time costs of an automotive fleet reduction
program and the recognition of higher employee benefit costs under new
accounting rules adopted in 1993. See Note 2 to the financial statements for
additional information concerning these new rules. Also, during 1993, O & M
expenses reflect costs associated with new demand-side option programs. These
costs were offset by increases in retail revenues. See Note 3 to the financial
statements for additional information on the recovery of demand-side option
program costs.
Depreciation and amortization expense increased slightly due to additional
plant investment. The 1992 decrease is due to the effects of lower
depreciation rates effective in October 1991. Taxes other than income taxes
increased 7.4 percent in 1993 and 3.8 percent in 1992.
4
<PAGE> 5
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 1993 Annual Report
These increases reflect higher ad valorem taxes. The 1993 increase also
includes higher taxes paid to municipalities as a result of increased sales.
Income tax expense increased $62 million in 1993 due primarily to higher
earnings and the effect of a one percent increase in the federal tax rate
effective January, 1993. Also, the Company incurred $27 million of tax expense
in connection with the second in a series of four separate transactions to sell
Plant Scherer Unit 4. The sale resulted in an after-tax gain of $18 million.
Interest expense and dividends on preferred stock decreased $19 million (4.0
percent) and $49 million (9.3 percent) in 1993 and 1992, respectively. These
reductions are due to significant refinancing of long-term debt and preferred
stock. The Company refinanced $1.7 billion of securities in both 1993 and
1992. In addition, the Company has retired $544 million of long-term debt with
the proceeds from the 1991 and 1993 Plant Scherer Unit 4 sales. Other interest
charges in 1993 include interest related to the settlement of an Internal
Revenue Service audit. The settlement, in total, did not have an effect on
1993 net income.
The Company has deferred certain expenses and recorded a deferred return
related to Plant Vogtle under phase-in plans. See Note 3 to the financial
statements under "Plant Vogtle Phase-In-Plans" for information regarding the
deferral and subsequent amortization of costs related to Plant Vogtle.
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 long-lived utility plant. Conventional accounting
for historical cost does not recognize either this economic loss or the
partially offsetting gain that arises through financing facilities with
fixed-money obligations such as long-term debt and preferred stock. 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 ranging from growth in energy sales to regulatory matters.
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, 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 1994 through 1996.
The scheduled addition of four combustion turbine generating units in 1994,
four units in 1995 and one unit in 1996, as well as the Rocky Mountain pumped
storage hydroelectric project in 1995, will increase related O & M and
depreciation expenses. See Note 4 to the financial statements for information
on regulatory uncertainties related to the Rocky Mountain project. The GPSC
has certified the construction of the 1994 and 1995 combustion turbine
generating units for meeting peak generating needs. In addition, the Company
has completed a demonstration competitive bidding process for its supply-side
requirements expected for 1996. The Company has filed with the GPSC for
certification of a four-year purchase power agreement beginning in 1996, and
for construction of a jointly owned combustion turbine to be completed in 1996
to meet these needs.
As part of efforts to curtail growth in operating expenses, the Company is
reducing its work force through an early-retirement program announced in
January 1994. The program resulted in a first quarter 1994 after-tax charge to
earnings of $39 million. The program has an expected payback period of
approximately two years.
Pursuant to an Integrated Resource Plan approved by the GPSC in 1992, the
Company has implemented various demand-side option programs and has been
authorized by the GPSC to recover associated program costs through rate riders.
On October 15, 1993, a superior court judge ruled that recovery of these costs
through rate riders is unlawful. The Company has ceased collection of the rate
riders and is deferring program costs as ordered by the
5
<PAGE> 6
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 1993 Annual Report
GPSC pending the final outcome of this matter. See Note 3 to the financial
statements for additional information.
The Company has completed two in a series of four separate transactions to
sell Unit 4 of Plant Scherer to two Florida utilities. The remaining
transactions are scheduled to take place in 1994 and 1995. If the sales take
place as planned, the Company would realize an additional after-tax gain
estimated to total approximately $20 million. See Note 5 to the financial
statements for additional information.
Compliance costs related to the Clean Air Act Amendments of 1990 (Clean Air
Act) could reduce earnings if such costs cannot be billed to customers. The
Clean Air Act is discussed later under "Environmental Issues."
The Energy Policy Act of 1992 (Energy Act) will have a profound effect on the
future of the electric utility industry. The Energy Act promotes energy
efficiency, alternative fuel use, and increased competition among electric
utilities. The law also includes provisions to streamline the licensing
process for new nuclear generating plants. The Energy Act marks the beginning
of a major change in the traditional business practices of selling electricity.
The Energy Act allows Independent Power Producers (IPPs) and other electric
suppliers access to a utility's transmission lines to sell their electricity to
other utilities. This may enhance the incentives for IPPs to build
cogeneration plants for the Company's large industrial and commercial
customers. If the Company does not remain a low cost producer and provide
quality service, the Company's sales growth could be limited and this could
significantly erode earnings.
The Company continues to compete with other electric suppliers within the
state. In Georgia, most new retail customers with more than 900 kilowatts of
connected load may choose their electricity supplier. In addition, the bulk
power market has become very competitive as utilities, IPPs and cogenerators
seek to supply future capacity needs. Competition can create new business
opportunities, but it increases risk and has the potential to adversely affect
earnings.
The Federal Energy Regulatory Commission (FERC) regulates wholesale rate
schedules and power sales contracts that the Company has with its sales for
resale customers. The FERC currently is reviewing the rate of return on common
equity included in these schedules and contracts and may require such returns
to be lowered, possibly retroactively. See Note 3 to the financial statements
under "FERC Review of Equity Returns" for additional information.
NEW ACCOUNTING STANDARDS
The Financial Accounting Standards Board (FASB) issued Statement No. 112,
Employers' Accounting for Postemployment Benefits, which must be adopted by
1994. The new standard requires that all types of benefits provided to former
or inactive employees and their families prior to retirement be accounted for
on an accrual basis. These benefits include salary continuation, severance
pay, supplemental unemployment benefits, disability-related benefits, job
training, and health and life insurance coverage. In 1993, the Company adopted
Statement No. 112, with no material effect on the financial statements.
The FASB has issued Statement No. 115, Accounting for Certain Investments in
Debt and Equity Securities, which will be effective in 1994. Statement No. 115
supersedes FASB Statement No. 12, Accounting for Certain Marketable
Securities. The Company adopted the new rules in January, 1994, with no
material effect on the financial statements.
FINANCIAL CONDITION
OVERVIEW
The principal changes in the Company's financial condition in 1993 were gross
utility plant additions of $674 million and the lowering of the cost of capital
achieved through the refinancing or retirement of $1.7 billion of long-term
debt and preferred stock.
On January 1, 1993, the Company changed its methods of accounting for
postretirement benefits other than pensions and for income taxes. See Notes 2
and 7 to the financial statements regarding the impact of these changes.
The funds needed for gross property additions are currently provided from
operations. The Statements of Cash Flows provide additional details.
6
<PAGE> 7
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 1993 Annual Report
FINANCING ACTIVITIES
In 1993, the Company continued to lower its financing costs by issuing new
securities and other debt, and retiring or repaying high-cost issues. New
issues during 1991 through 1993 totaled $3.0 billion and retirement or
repayment of securities totaled $4.2 billion. The retirements included the
redemption of $253 million and $291 million in 1993 and 1991, respectively, of
first mortgage bonds with the proceeds from the Plant Scherer Unit 4 sales.
Composite financing rates for the years 1991 through 1993, as of year-end,
were as follows:
<TABLE>
<CAPTION>
1993 1992 1991
<S> <C> <C> <C>
Composite interest rate
on long-term debt 7.86% 8.49% 9.05%
Composite preferred stock
dividend rate 6.76% 7.52% 7.99%
</TABLE>
The Company's current securities ratings are as follows:
<TABLE>
<CAPTION>
Duff & Standard
Phelps Moody's & Poor's
<S> <C> <C> <C>
First Mortgage Bonds A+ A3 A-
Preferred Stock A- baa1 BBB+
Unsecured Bonds A Baa1 BBB+
Commercial Paper * P2 A2
</TABLE>
* Not rated by Duff & Phelps
LIQUIDITY AND CAPITAL REQUIREMENTS
Cash provided from operations increased by $236 million in 1993, primarily due
to higher retail sales, lower interest costs, decreasing capacity purchases
from the co-owners of plants Vogtle and Scherer and the receipt of cash
payments from Gulf States that completed the settlement of litigation.
The Company estimates that construction expenditures for the years 1994
through 1996 will total $688 million, $555 million and $629 million,
respectively. The Company will continue to invest in transmission and
distribution facilities and enhance existing generating plants. These
expenditures also include amounts for nine combustion turbine generating units
and equipment that will be required to comply with the provisions of the Clean
Air Act.
The Company's contractual capacity purchases will decline by $113 million
over the next three years. Cash requirements for sinking fund requirements,
redemptions announced, and maturities of long-term debt are expected to total
$377 million during 1994 through 1996.
As a result of requirements by the Nuclear Regulatory Commission, the Company
has established external sinking funds for the purpose of funding nuclear
decommissioning costs. For 1994 through 1996, the amount to be funded for the
Company totals $16 million annually. For additional information concerning
nuclear decommissioning costs, see Note 1 to the financial statements under
"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 $540 million of
unused credit arrangements with banks at the beginning of 1994. See Note 8 to
the financial statements for additional information.
Completing the remaining two transactions for the sale of Plant Scherer Unit
4 will generate approximately $130 million in both 1994 and in 1995.
The Company is required to meet certain coverage requirements specified in
its mortgage indenture and corporate charter to issue new first mortgage bonds
and preferred stock. The Company's ability to satisfy all coverage
requirements is such that it could issue new first mortgage bonds and preferred
stock to provide sufficient funds for all anticipated requirements.
ENVIRONMENTAL ISSUES
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 -- will have a
significant impact on The Southern Company. Specific reductions in sulfur
dioxide and nitrogen oxide emissions from fossil-fired generating plants will
be required in two phases. Phase I compliance must be implemented in 1995 and
affects eight generating plants -- some 10,000 megawatts
7
<PAGE> 8
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 1993 Annual Report
of capacity or 35 percent of total capacity -- in the Southern electric system.
Phase II compliance is required in 2000, and all fossil-fired generating plants
in the Southern electric system will be affected.
Beginning in 1995, the Environmental Protection Agency (EPA) will allocate
annual sulfur dioxide emission allowances through the newly established
allowance trading program. An emission allowance is the authority to emit one
ton of sulfur dioxide during a calendar year. The method for allocating
allowances is based on the fossil fuel consumed from 1985 through 1987 for each
affected generating unit. Emission allowances are transferable and can be
bought, sold, or banked and used in the future.
The sulfur dioxide emission allowance program is expected to minimize the
cost of compliance. The market for emission allowances is developing slower
than expected. However, The Southern Company's sulfur dioxide compliance
strategy is designed to take advantage of allowances as the market develops.
The Southern Company expects to achieve Phase I sulfur dioxide compliance at
the eight affected plants by switching to low-sulfur coal, and this has
required some equipment upgrades. This compliance strategy is expected to
result in unused emission allowances being banked for later use. Additional
construction expenditures are required to install equipment for the control of
nitrogen oxide emissions at these eight plants. Also, continuous emissions
monitoring equipment would be installed on all fossil-fired units. Under this
Phase I compliance approach, Georgia Power's construction expenditures are
estimated to total approximately $150 million through 1995.
Phase II compliance costs are expected to be higher because requirements are
stricter and all fossil-fired generating plants are affected. For sulfur
dioxide compliance, The Southern Company could use emission allowances banked
during Phase I, increase fuel switching, install flue gas desulfurization
equipment at selected plants, and/or purchase more allowances depending on the
price and availability of allowances. Also, in Phase II, equipment to control
nitrogen oxide emissions will be installed on additional system fossil-fired
plants as required to meet anticipated Phase II limits. Therefore, during the
period 1996 to 2000, compliance could require total Georgia Power construction
expenditures ranging from approximately $150 million to $325 million. However,
the full impact of Phase II compliance cannot now be determined with certainty,
pending the development of a market for emission allowances, the completion of
EPA regulations, and the possibility of new emission reduction technologies.
An increase of up to 2 percent in Georgia Power's annual revenue
requirements from customers could be necessary to fully recover the cost of
compliance for both Phase I and Phase II of the Clean Air Act. Compliance
costs include construction expenditures, increased costs for switching to
low-sulfur coal, and costs related to emission allowances. There can be no
assurance that all Clean Air Act costs will be recovered.
Metropolitan Atlanta is classified as a non-attainment area with regard to
the ozone ambient air quality standards. Title I of the Clean Air Act requires
the state of Georgia to conduct specific studies and establish new control
rules by November 1994 -- affecting sources of nitrogen oxides and volatile
organic compounds -- to achieve attainment by 1999. As the required first
step, the state has issued rules for the application of reasonably available
control technology to reduce nitrogen oxide emissions by May 31, 1995. The
results of these new rules require nitrogen oxide controls, above Title IV
requirements, on some Company plants. Final attainment rules, based on
modeling studies, could require installation of additional controls for
nitrogen oxide emissions as early as 1997. Compliance with any new rules could
result in significant additional costs. The impact of new rules will depend on
the development and implementation of such rules.
Title III of the Clean Air Act requires a multi-year EPA study of power
plant emissions of hazardous air pollutants. The study will serve as the basis
for a decision on whether additional regulatory control of these substances is
warranted. Compliance with any new control standards could result in
significant additional costs. The impact of new standards -- if any -- will
depend on the development and implementation of applicable regulations.
The EPA continues to evaluate the need for a new short-term ambient air
quality standard for sulfur dioxide. Preliminary results from an EPA study on
the impact of a
8
<PAGE> 9
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 1993 Annual Report
new standard indicate that a number of plants could be required to install
sulfur dioxide controls. These controls would be in addition to the controls
already required to meet the acid rain provision of the Clean Air Act. The EPA
is expected to take some action on this issue in 1994. In addition, the EPA is
evaluating the need to revise the ambient air quality standards for particulate
matter, nitrogen oxides, and ozone. The impact of any new standards will
depend on the level chosen for the standards and cannot be determined at this
time.
In 1994 or 1995, the EPA is expected to issue revised rules on air quality
control regulations related to stack height requirements of the Clean Air Act.
The full impact of the final rules cannot be determined at this time, pending
their development and implementation.
In 1993, the EPA issued a ruling confirming the nonhazardous status of coal
ash. However, the EPA has until 1998 to classify co-managed utility wastes --
coal ash and other utility wastes -- as either nonhazardous or hazardous. If
the EPA classifies the co-managed wastes as hazardous, then substantial
additional costs for the management of such wastes may be required. The full
impact of any change in the regulatory status will depend on the subsequent
development of co-managed waste requirements.
The Company must comply with other environmental laws and regulations that
cover the handling and disposal of hazardous waste. These laws include the
Comprehensive Environmental Response Compensation and Liability Act of 1980
(CERCLA or Superfund). 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 costs to clean-up known sites in the financial statements.
Several major pieces of environmental legislation are in the process of
being reauthorized or amended by Congress. These include: the Clean Water
Act; the Comprehensive Environmental Response, Compensation, and Liability Act;
and the Resource Conservation and Recovery Act. Changes to these laws could
affect many areas of the Company's operations. The full impact of these
requirements cannot be determined at this time, pending the development and
implementation of applicable regulations.
Compliance with possible new 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 for lawsuits alleging damages caused
by electromagnetic fields exists.
9
<PAGE> 10
STATEMENTS OF INCOME
For the Years Ended December 31, 1993, 1992, and 1991
Georgia Power Company 1993 Annual Report
<TABLE>
<CAPTION>
1993 1992 1991
(in thousands)
<S> <C> <C> <C>
OPERATING REVENUES:
Revenues (Note 1) $ 4,389,513 $ 4,229,601 4,235,842
Revenues from affiliates 61,668 67,835 65,586
Total operating revenues 4,451,181 4,297,436 4,301,428
OPERATING EXPENSES:
Operation --
Fuel 951,507 929,780 998,701
Purchased power from non-affiliates 313,170 436,761 444,920
Purchased power from affiliates 194,024 158,306 193,114
Provision for separation benefits - 9,778 52,952
Proceeds from settlement of disputed contracts (Note 3) - (4,982) (142,183)
Other 675,284 616,116 596,565
Maintenance 284,521 264,757 295,012
Depreciation and amortization 379,425 375,460 382,549
Amortization of deferred Plant Vogtle expenses, net
(Note 3) 36,284 (30,804) 16,008
Taxes other than income taxes 192,671 179,460 172,893
Federal and state income taxes 452,122 377,542 349,284
Total operating expenses 3,479,008 3,312,174 3,359,815
OPERATING INCOME 972,173 985,262 941,613
OTHER INCOME (EXPENSE):
Allowance for equity funds used during construction 3,168 5,855 9,083
Income from subsidiary (Note 5) 4,127 4,635 4,576
Deferred return on Plant Vogtle - - 34,549
Interest income 3,806 12,475 10,563
Other, net 11,902 (30,527) 13,551
Income taxes applicable to other income 37,661 25,163 (7,522)
INCOME BEFORE INTEREST CHARGES 1,032,837 1,002,863 1,006,413
INTEREST CHARGES:
Interest on long-term debt 343,634 402,541 459,184
Allowance for debt funds used during construction (8,271) (8,310) (10,385)
Interest on interim obligations 15,530 9,694 4,906
Amortization of debt discount, premium, and expense, net 14,024 8,033 6,214
Other interest charges 47,393 12,425 9,938
Net interest charges 412,310 424,383 469,857
NET INCOME 620,527 578,480 536,556
DIVIDENDS ON PREFERRED STOCK 50,674 57,942 61,701
NET INCOME AFTER DIVIDENDS ON PREFERRED STOCK $ 569,853 $ 520,538 474,855
</TABLE>
The accompanying notes are an integral part of these statements.
10
<PAGE> 11
BALANCE SHEETS
At December 31, 1993 and 1992
Georgia Power Company 1993 Annual Report
<TABLE>
<CAPTION>
ASSETS 1993 1992
(in thousands)
<S> <C> <C>
UTILITY PLANT:
Plant in service (Note 1) $ 13,743,521 $ 13,613,361
Less accumulated provision for depreciation 3,822,344 3,569,717
9,921,177 10,043,644
Nuclear fuel, at amortized cost (Note 1) 135,742 155,194
Construction work in progress (Note 4) 584,013 405,606
Total 10,640,932 10,604,444
Less property-related accumulated deferred income taxes (Note 7) - 1,589,743
Total 10,640,932 9,014,701
OTHER PROPERTY AND INVESTMENTS:
Southern Electric Generating Company, at equity (Note 5) 29,201 30,703
Nuclear decommissioning trusts (Note 1) 37,937 20,311
Miscellaneous 31,941 24,760
Total 99,079 75,774
CURRENT ASSETS:
Cash and cash equivalents 5,896 22,114
Investment securities - 108,206
Receivables-
Customer accounts receivable 486,947 357,923
Other accounts and notes receivable 117,249 96,915
Affiliated companies 14,832 22,674
Accumulated provision for uncollectible accounts (4,300) (4,121)
Fossil fuel stock, at average cost 111,620 197,332
Materials and supplies, at average cost 287,551 284,272
Prepayments 65,269 91,447
Vacation pay deferred (Note 1) 41,575 40,169
Total 1,126,639 1,216,931
DEFERRED CHARGES:
Deferred charges related to income taxes (Note 7) 992,510 -
Deferred Plant Vogtle costs (Note 3) 506,980 383,025
Debt expense, being amortized 20,730 17,719
Premium on reacquired debt, being amortized 153,146 116,940
Miscellaneous 196,094 139,352
Total 1,869,460 657,036
TOTAL ASSETS $ 13,736,110 $ 10,964,442
</TABLE>
The accompanying notes are an integral part of these statements.
11
<PAGE> 12
BALANCE SHEETS
At December 31, 1993 and 1992
Georgia Power Company 1993 Annual Report
<TABLE>
<CAPTION>
CAPITALIZATION AND LIABILITIES 1993 1992
(in thousands)
<S> <C> <C>
CAPITALIZATION (SEE ACCOMPANYING STATEMENTS):
Common stock equity $ 4,045,458 $ 3,888,237
Preferred stock 692,787 692,792
Preferred stock subject to mandatory redemption - 6,250
Long-term debt 4,031,387 4,131,016
Total 8,769,632 8,718,295
CURRENT LIABILITIES:
Preferred stock due within one year (Note 8) - 63,750
Long-term debt due within one year (Note 8) 10,543 95,823
Notes payable to banks (Note 8) 406,700 400,200
Commercial paper (Note 8) 75,527 133,471
Accounts payable-
Affiliated companies 38,115 33,258
Other 285,929 284,093
Customer deposits 45,922 45,145
Taxes accrued-
Federal and state income 31,639 43,779
Other 121,854 94,510
Interest accrued 110,497 132,319
Vacation pay accrued 40,060 38,694
Miscellaneous 64,527 89,355
Total 1,231,313 1,454,397
DEFERRED CREDITS AND OTHER LIABILITIES:
Accumulated deferred income taxes (Note 7) 2,479,720 -
Accumulated deferred investment tax credits 478,334 515,539
Disallowed Plant Vogtle capacity buyback costs (Note 5) 63,067 72,201
Deferred credits related to income taxes (Note 7) 452,819 -
Miscellaneous 261,225 204,010
Total 3,735,165 791,750
COMMITMENTS AND CONTINGENT MATTERS (NOTES 2, 3, 4, 5, 6)
TOTAL CAPITALIZATION AND LIABILITIES $ 13,736,110 $ 10,964,442
</TABLE>
The accompanying notes are an integral part of these statements.
12
<PAGE> 13
STATEMENTS OF CAPITALIZATION
AT December 31, 1993 and 1992
Georgia Power Company 1993 Annual Report
<TABLE>
<CAPTION>
1993 1992 1993 1992
(in thousands) (percent of total)
<S> <C> <C> <C> <C>
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 2,384,348 2,384,140
Premium on preferred stock 413 467
Retained earnings (Note 8) 1,316,447 1,159,380
Total common stock equity 4,045,458 3,888,237 46.1 % 44.6 %
CUMULATIVE PREFERRED STOCK, WITHOUT PAR VALUE:
Authorized -- 55,000,000 shares in 1993;
52,200,000 shares in 1992
Outstanding -- 21,027,923 shares in 1993;
$100 stated value --
4.60% to 5.64% 95,787 95,792
6.48% to 7.80% 127,000 127,000
8.20% to 9.08% - 25,000
$25 stated value --
$1.90 to $2.125 295,000 295,000
Adjustable rate -- at January 1, 1994:
4.98% 100,000 -
5.42% 75,000 -
6.57% - 50,000
7.02% - 50,000
7.57% - 50,000
Total (annual dividend requirement -- $46,851,000) 692,787 692,792 7.9 7.9
CUMULATIVE PREFERRED STOCK SUBJECT TO MANDATORY
REDEMPTION, WITHOUT PAR VALUE:
Authorized and Outstanding -- 2,800,000 shares in 1992
$25 stated value --
$2.43 - 45,000
$2.50 - 25,000
Total - 70,000
Less amount due within one year - 63,750
Total excluding amount due within one year - 6,250 - 0.1
</TABLE>
13
<PAGE> 14
STATEMENTS OF CAPITALIZATION
At December 31, 1993 and 1992
Georgia Power Company 1993 Annual Report
<TABLE>
1993 1992 1993 1992
<S> <C> <C> <C> <C>
LONG-TERM DEBT: (in thousands) (percent of total)
First mortgage bonds --
Maturity Interest Rates
October 1, 1994 4 5/8% - 28,000
September 1, 1995 4 7/8% - 36,500
September 1, 1995 5 1/8% 130,000 130,000
March 1, 1996 4 3/4% 150,000 -
July 1, 1996 5 3/4% - 45,368
September 1, 1997 6 1/2% - 50,000
April 1, 1998 5 1/2% 100,000 -
September 1, 1998 6 5/8% - 50,000
1999 through 2003 6 % to 7 7/8% 820,000 929,500
2008 6 7/8% 50,000 -
2016 through 2018 10% to 10 3/4% 69,716 663,170
2019 through 2023 7.55% to 9.23% 760,000 300,000
2020 variable rate - 50,000
2032 variable rates 200,000 200,000
Total first mortgage bonds 2,279,716 2,482,538
Pollution control obligations (Note 8) 1,661,250 1,661,290
Other long-term debt (Note 8) 135,058 117,344
Unamortized debt premium (discount), net (34,094) (34,333)
Total long-term debt (annual interest
requirement -- $320,505,000) 4,041,930 4,226,839
Less amount due within one year (Note 8) 10,543 95,823
Long-term debt excluding amount due within one year 4,031,387 4,131,016 46.0 47.4
TOTAL CAPITALIZATION $ 8,769,632 $ 8,718,295 100.0 % 100.0%
</TABLE>
The accompanying notes are an integral part of these statements.
14
<PAGE> 15
STATEMENTS OF RETAINED EARNINGS
For the Years Ended December 31, 1993, 1992, and 1991
Georgia Power Company 1993 Annual Report
<TABLE>
<CAPTION>
1993 1992 1991
(in thousands)
<S> <C> <C> <C>
BALANCE AT BEGINNING OF PERIOD $ 1,159,380 $ 1,038,012 $ 944,774
Net income after dividends on preferred stock 569,853 520,538 474,855
Cash dividends on common stock (402,400) (384,000) (375,200)
Preferred stock transactions, net (10,386) (15,170) (6,417)
BALANCE AT END OF PERIOD (NOTE 8) $ 1,316,447 $ 1,159,380 $ 1,038,012
STATEMENTS OF PAID-IN CAPITAL
For the Years Ended December 31, 1993, 1992, and 1991
Georgia Power Company 1993 Annual Report
1993 1992 1991
(in thousands)
BALANCE AT BEGINNING OF PERIOD $ 2,384,140 $ 2,383,800 $ 2,383,800
Contributions to capital by parent company 208 340 -
BALANCE AT END OF PERIOD $ 2,384,348 $ 2,384,140 $ 2,383,800
</TABLE>
The accompanying notes are an integral part of these statements.
15
<PAGE> 16
STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 1993, 1992, and 1991
Georgia Power Company 1993 Annual Report
<TABLE>
<CAPTION>
1993 1992 1991
(in thousands)
<S> <C> <C> <C>
OPERATING ACTIVITIES:
Net income $ 620,527 $ 578,480 $ 536,556
Adjustments to reconcile net income to net
cash provided by operating activities --
Depreciation and amortization 475,152 471,014 480,318
Deferred income taxes and investment tax credits, net 150,735 189,251 43,695
Allowance for equity funds used during construction (3,168) (5,855) (9,083)
Deferred Plant Vogtle costs 36,284 (30,804) (18,541)
Non-cash proceeds from settlement of disputed contracts
(Note 3) - (4,982) (103,846)
Provision for separation benefits - - 52,952
Gain on asset sales (35,514) (12) (36,835)
Other, net (10,713) (9,756) (42,141)
Changes in certain current assets and liabilities --
Receivables, net 27,088 (31,348) 23,920
Inventories 82,433 (65,621) 24,130
Payables 17,364 25,303 (23,075)
Taxes accrued 15,377 (22,828) 76,932
Energy cost recovery, retail (74,260) (46,615) (4,594)
Other (35,691) (16,518) (17,561)
Net cash provided from operating activities 1,265,614 1,029,709 982,827
INVESTING ACTIVITIES:
Gross property additions (674,432) (508,444) (548,051)
Sales of property 261,687 46 291,075
Other (43,154) 42,892 931
Net cash used for investing activities (455,899) (465,506) (256,045)
FINANCING ACTIVITIES AND CAPITAL CONTRIBUTIONS:
Proceeds:
Preferred stock 175,000 195,000 100,000
First mortgage bonds 1,135,000 975,000 -
Pollution control bonds 145,425 161,955 80,420
Long-term notes 37,000 - -
Retirements:
Preferred stock (245,005) (165,004) (100,000)
First mortgage bonds (1,337,822) (1,381,300) (598,384)
Pollution control bonds (145,465) (160,205) (83,265)
Other long-term debt (19,451) (567) (1,130)
Interim obligations, net (51,444) 334,671 199,000
Payment of preferred stock dividends (53,123) (60,475) (60,766)
Payment of common stock dividends (402,400) (384,000) (375,200)
Miscellaneous (63,648) (70,986) (17,613)
Net cash used for financing activities (825,933) (555,911) (856,938)
NET CHANGE IN CASH AND CASH EQUIVALENTS (16,218) 8,292 (130,156)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR 22,114 13,822 143,978
CASH AND CASH EQUIVALENTS AT END OF YEAR $ 5,896 $ 22,114 $ 13,822
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid during the year for --
Interest (net of amount capitalized) $420,107 $435,203 $488,431
Income taxes 275,867 190,674 214,809
</TABLE>
The accompanying notes are an integral part of these statements.
16
<PAGE> 17
NOTES TO FINANCIAL STATEMENTS
Georgia Power Company 1993 Annual Report
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
GENERAL
The Company is a wholly owned subsidiary of The Southern Company, which is the
parent company of five operating companies, Southern Company Services (SCS),
Southern Electric International (Southern Electric), and Southern Nuclear
Operating Company (Southern Nuclear), and various other subsidiaries related to
foreign utility operations and domestic non-utility operations. 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. Intracompany contracts dealing
with jointly owned generating facilities, transmission lines and exchange of
electric power are regulated by the Federal Energy Regulatory Commission (FERC)
or the Securities and Exchange Commission. SCS provides, at cost, specialized
services to The Southern Company and each of the subsidiary companies.
Southern Electric designs, builds, owns, and operates power production
facilities and provides a broad range of technical services to industrial
companies and utilities in the United States and a number of international
markets. Southern Nuclear provides support services for nuclear power plants
in the Southern electric system.
The Southern Company is registered as a holding company under the Public
Utility Holding Company Act of 1935. Both The 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 and complies with the accounting policies and practices prescribed
by the respective regulatory commissions.
Certain prior years' data presented in the financial statements have been
reclassified to conform with current year presentation.
REVENUES AND FUEL COSTS
The Company accrues revenues for services rendered but unbilled at the end of
each fiscal period. Fuel costs are expensed as fuel is used. The Company is
authorized by state law and FERC regulations to recover fuel costs and the fuel
component of purchased energy costs through fuel cost recovery provisions,
which are periodically adjusted to reflect increases or decreases in such
costs. Revenues are adjusted for differences between recoverable fuel costs
and amounts actually recovered in current rates. Fuel costs were under
recovered by $79 million and $4 million at December 31, 1993, and 1992,
respectively. These amounts are included in customer accounts receivable on
the balance sheets. The fuel cost recovery rate was increased effective
December 6, 1993.
The cost of nuclear fuel is amortized to fuel expense based on estimated
thermal units used to generate electric energy and includes a provision for the
disposal of spent fuel. Total charges for nuclear fuel amortized to expense
were $75 million in 1993, $84 million in 1992, and $93 million in 1991. The
Company has contracted with the U.S. Department of Energy (DOE) for permanent
disposal of spent fuel beginning in 1998; however, the actual year this service
will begin is uncertain. Pending permanent disposition of the spent fuel,
sufficient storage capacity is available at Plant Hatch into 2003 and at Plant
Vogtle into 2009. 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 law provides that utilities will recover these payments in the same manner
as any other fuel expense. The Company -- based on its ownership interest --
estimates its total assessment under this law to be approximately $42 million
to be paid over a 15-year period beginning in 1993. This obligation is
recognized in the accompanying Balance Sheets and is being recovered through
the fuel cost recovery provisions. The remaining liability at December 31,
1993, is $39 million.
17
<PAGE> 18
NOTES (continued)
Georgia Power Company 1993 Annual Report
NUCLEAR REFUELING OUTAGE COSTS
Prior to 1992, the Company expensed nuclear refueling outage costs as incurred
during the outage period. Pursuant to the 1991 GPSC retail rate order, the
Company began accounting for these costs on a normalized basis in 1992. Under
this method of accounting, refueling outage costs are deferred and subsequently
amortized to expense over the operating cycle of each unit, which is normally
18 months. Deferred nuclear outage costs were $17 million and $6 million at
December 31, 1993 and 1992, respectively.
DEPRECIATION
Depreciation is provided on the cost of depreciable utility plant in service
and is calculated primarily on the straight-line basis over the estimated
composite service life of the property. The composite rate of depreciation was
3.1 percent in 1993 and 1992, and 3.2 percent in 1991. Effective October 1991,
the Company adopted lower depreciation rates consistent with the 1991 GPSC
retail rate order. When a property unit is retired or otherwise disposed of in
the normal course of business, its costs and the costs of removal, less
salvage, are charged to the accumulated provision for depreciation. Minor
items of property included in the cost of the plant are retired when the
related property unit is retired.
NUCLEAR DECOMMISSIONING
In 1988, the Nuclear Regulatory Commission (NRC) adopted regulations requiring
all licensees operating commercial nuclear power reactors to establish a plan
for providing, with reasonable assurance, funds for decommissioning.
Reasonable assurance may be in the form of an external sinking fund, a surety
method, or prepayment. The Company has established external trust funds to
comply with the NRC's regulations. Prior to the enactment of these
regulations, the Company had internally reserved nuclear decommissioning costs.
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 estimated cost of decommissioning and the amounts being recovered through
rates at December 31, 1993, for the Company's ownership interest in plants
Hatch and Vogtle were as follows:
<TABLE>
<CAPTION>
Plant Plant
Hatch Vogtle
<S> <C> <C>
Site study basis (year) 1990 1990
Estimated completion of
decommissioning (year) 2027 2037
Cost of decommissioning: (in millions)
Radiated structures $184 $155
Non-radiated structures 35 62
Contingency 55 54
Total costs $274 $271
(in millions)
Approved for ratemaking $184 $155
Amount expensed in 1993 $ 6 $ 6
Balance in external trust fund $ 22 $ 16
Balance in internal reserve $ 33 $ 11
</TABLE>
The amounts in the internal reserve are being transferred into the external
trust fund over a period of approximately nine years as approved by the GPSC in
its 1991 retail rate order.
The estimates approved by the GPSC for ratemaking exclude costs of
non-radiated structures and site contingency costs. The actual decommissioning
cost may vary from the above estimates because of regulatory requirements,
changes in technology, and increased costs of labor, materials, and equipment.
The decommissioning cost estimates are based on prompt dismantlement and
removal of the plant from service. The Company expects the GPSC to
periodically review and adjust, if necessary, the amounts collected in rates
for the anticipated cost of decommissioning.
PLANT VOGTLE PHASE-IN PLANS
In 1987 and 1989, the GPSC ordered that the costs of Plant Vogtle Units 1 and 2
be phased into rates under plans that meet the requirements of Financial
Accounting Standards Board (FASB) Statement No. 92, Accounting for Phase-In
Plans. In 1991, the GPSC modified the phase-in plans. In addition, the
Company deferred certain Plant Vogtle operating expenses and financing costs
under accounting orders issued by the GPSC. See Note 3 for further
information.
18
<PAGE> 19
NOTES (continued)
Georgia Power Company 1993 Annual Report
INCOME TAXES
The Company 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.
In years prior to 1993, income taxes were accounted for and reported under
Accounting Principles Board Opinion No. 11. Effective January 1, 1993, the
Company adopted FASB Statement No. 109, Accounting for Income Taxes. See Note
7 to the financial statements for further information.
ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION (AFUDC) AND DEFERRED RETURN
AFUDC represents the estimated debt and equity costs of capital funds that are
necessary to finance the construction of new facilities. While cash is not
realized currently from such allowance, it increases the revenue requirement
over the service life of the plant through a higher rate base and higher
depreciation expense. For the years 1993, 1992 and 1991, the average AFUDC
rates were 4.87 percent, 7.16 percent and 9.90 percent, respectively. The
reduction in the average AFUDC rate since 1991 reflects the Company's greater
use of lower cost short-term debt.
The Company also imputed a return on its investment in Plant Vogtle Units 1
and 2 after they began commercial operation, under short-term cost deferrals
and phase-in plans as described in Note 3. AFUDC and the Vogtle deferred
returns, net of taxes, as a percentage of net income after dividends on
preferred stock, amounted to 1.4 percent, 2.1 percent and 9.2 percent for 1993,
1992 and 1991, respectively.
UTILITY PLANT
Utility plant is stated at original cost with the exception of Plant Vogtle,
which is stated at cost less regulatory disallowances. Original cost includes
materials; labor; appropriate administrative and general costs; payroll-related
costs such as taxes, pensions, and other benefits; and the estimated cost of
funds used during construction.
CASH AND CASH EQUIVALENTS
For purposes of the Statements of Cash Flows, temporary cash investments are
considered cash equivalents. Temporary cash investments are securities with
original maturities of 90 days or less.
FINANCIAL INSTRUMENTS
All financial instruments of the Company -- for which the carrying amount does
not approximate fair value -- are shown in the table below at December 31:
<TABLE>
<CAPTION>
1993
Carrying Fair
Amount Value
(in millions)
<S> <C> <C>
Nuclear decommissioning trusts $ 38 $ 40
Long-term debt 3,954 4,197
1992
Carrying Fair
Amount Value
(in millions)
Nuclear decommissioning trusts $ 20 $ 21
Investment securities 108 121
Long-term debt 4,130 4,404
Preferred stock subject to
mandatory redemption 70 76
</TABLE>
The fair values of nuclear decommissioning trusts and investment securities
were based on listed closing market prices. The fair values for long-term debt
and preferred stock subject to mandatory redemption 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. In December 1992, the Company converted to the
inventory method of accounting for certain emergency spare parts. This
conversion resulted in a regulatory liability that is being amortized as
credits to income over
19
<PAGE> 20
NOTES (continued)
Georgia Power Company 1993 Annual Report
approximately four years. This conversion will not have a material effect on
income in any year.
VACATION PAY
Company employees earn vacation in one year and take it in the subsequent year.
However, for ratemaking purposes, vacation pay is recognized as an allowable
expense only when paid. Consistent with this ratemaking treatment, the Company
accrues a current liability for earned vacation pay and records a current asset
representing the future recoverability of this cost. This amount was $42
million at December 31, 1993, and $40 million at December 31, 1992. In 1994,
approximately 72 percent of the 1993 deferred vacation costs will be expensed,
and the balance will be charged to construction and other accounts.
2. RETIREMENT BENEFITS
PENSION PLAN
The Company has a defined benefit, trusteed, non-contributory pension plan
covering substantially all regular employees. Benefits are based on the
greater of amounts resulting from two different formulas: years of service and
final average pay or years of service and a flat dollar benefit. The Company
uses the "entry age normal method with a frozen initial liability" actuarial
method for funding purposes, subject to limitations under federal income tax
regulations. Amounts funded to the pension fund are primarily invested in
equity and fixed-income securities. FASB Statement No. 87, Employers'
Accounting for Pensions, requires use of the projected unit credit actuarial
method for financial reporting purposes.
POSTRETIREMENT BENEFITS
The Company also provides certain medical care and life insurance benefits for
retired employees. Substantially all employees may become eligible for these
benefits when they retire. For medical care benefits, a qualified trust has
been established for funding amounts to the extent deductible under federal
income tax regulations. Amounts funded are primarily invested in debt and
equity securities. Accrued costs of life insurance benefits, other than
current cash payments for retirees, currently are not being funded.
Effective January 1, 1993, the Company adopted FASB Statement No. 106,
Employers' Accounting for Postretirement Benefits Other Than Pensions, on a
prospective basis. Statement No. 106 requires that medical care and life
insurance benefits for retired employees be accounted for on an accrual basis
using a specified actuarial method, "benefit/years-of-service."
In October 1993, the GPSC ordered the Company to phase in the adoption of
Statement No. 106 to cost of service over a five-year period, whereby one-fifth
of the additional expense was recognized -- approximately $6 million -- in 1993
and the remaining additional expense was deferred. An additional one-fifth of
the costs will be expensed each succeeding year until the costs are fully
reflected in cost of service in 1997. The cost deferred during the five-year
period will be amortized to expense over a 15-year period beginning in 1998.
As a result of the regulatory treatment allowed by the GPSC, the adoption of
Statement No. 106 did not have a material impact on net income.
Prior to 1993, the Company recognized these cost on a cash basis as payments
were made. The total costs of such benefits recognized by the Company in 1993,
1992, and 1991 were $56 million, $13 million, and $9 million, respectively.
STATUS AND COST OF BENEFITS
Shown in the following tables are actuarial results and assumptions for pension
and postretirement medical and life insurance benefits as computed under the
requirements of Statement Nos. 87 and 106, respectively. Retiree medical and
life insurance information is shown only for 1993 because Statement No. 106
was adopted as
20
<PAGE> 21
NOTES (continued)
Georgia Power Company 1993 Annual Report
of January 1, 1993, on a prospective basis. The funded status of the plans at
December 31 was as follows:
<TABLE>
<CAPTION>
Pension
1993 1992
(in millions)
<S> <C> <C>
Actuarial present value of
benefit obligations:
Vested benefits $ 655 $ 557
Non-vested benefits 35 26
Accumulated benefit obligation 690 583
Additional amounts related
to projected salary increases 257 293
Projected benefit obligation 947 876
Less:
Fair value of plan assets 1,495 1,341
Unrecognized net gain (490) (413)
Unrecognized prior service cost 31 33
Unrecognized transition asset (62) (67)
Prepaid asset recognized in the Balance
Sheets $ 27 $ 18
</TABLE>
<TABLE>
<CAPTION>
Postretirement
Medical Life
1993
(in millions)
<S> <C> <C>
Actuarial present value of
benefit obligation:
Retirees and dependents $136 $32
Employees eligible to retire 12 -
Other employees 206 40
Accumulated benefit obligation 354 72
Less:
Fair value of plan assets 30 1
Unrecognized net loss (gain) 40 (6)
Unrecognized transition
obligation 251 69
Accrued liability recognized in the
Balance Sheets $ 33 $ 8
</TABLE>
Weighted average rates used in actuarial calculations:
<TABLE>
<CAPTION>
1993 1992 1991
<S> <C> <C> <C>
Discount 7.5% 8.0% 8.0%
Annual salary increase 5.0 6.0 6.0
Long-term return on plan
assets 8.5 8.5 8.5
</TABLE>
An additional assumption used in measuring the accumulated postretirement
medical benefit obligation was a weighted average medical care cost trend rate
of 11.3 percent for 1993, decreasing gradually to 6.0 percent through the year
2000 and remaining at that level thereafter. An annual increase in the assumed
medical care cost trend rate by 1.0 percent would increase the accumulated
medical benefit obligation as of December 31, 1993, by $68 million and the
aggregate of the service and interest cost components of the net retiree
medical cost by $7 million.
The components of the plans' net costs are shown below:
<TABLE>
<CAPTION>
Pension
1993 1992 1991
(in millions)
<S> <C> <C> <C>
Benefits earned during the $ 33 $ 34 $ 32
year
Interest cost on projected
benefit obligation 69 65 61
Actual return on plan assets (194) (61) (334)
Net amortization and deferral 84 (38) 247
Net pension cost (income) $ (8) $ - $ 6
</TABLE>
Of net pension costs (income) recorded, $(6) million in 1993 and $5 million
in 1991, were recorded to operating expense, with the balance being recorded to
construction and other accounts.
<TABLE>
<CAPTION>
Postretirement
Medical Life
1993
(in millions)
<S> <C> <C>
Benefits earned during the year $11 $ 3
Interest cost on accumulated
benefit obligation 23 6
Amortization of transition
obligation over 20 years 12 3
Actual return on plan assets (4) -
Net amortization and deferral 2 -
Net postretirement cost $44 $12
</TABLE>
21
<PAGE> 22
NOTES (continued)
Georgia Power Company 1993 Annual Report
Of the above net postretirement medical and life insurance costs recorded
in 1993, $21 million was charged to operating expenses, $21 million was
deferred, and the remainder was charged to construction and other accounts.
3. LITIGATION AND REGULATORY MATTERS
DEMAND-SIDE CONSERVATION PROGRAMS
In October 1993, a Superior Court of Fulton County, Georgia, judge ruled that
rate riders previously approved by the GPSC for recovery of the Company's costs
incurred in connection with demand-side conservation programs were unlawful.
The judge held that the GPSC lacked statutory authority to approve such rate
riders except through general rate case proceedings and that those procedures
had not been followed. The Company has suspended collection of the demand-side
conservation costs and appealed the court's decision to the Georgia Court of
Appeals. In December 1993, the GPSC approved the Company's request for an
accounting order allowing the Company to defer all current unrecovered and
future costs related to these programs until the court's decision is reversed
or until the next general rate case proceeding. An association of industrial
customers has filed a petition for review of such accounting order in the
Superior Court of Fulton County, Georgia. The Company's costs related to these
conservation programs through 1993 were $60 million of which $15 million has
been collected and the remainder deferred. The estimated costs, assuming no
change in the programs certified by the GPSC, are $38 million in 1994 and $40
million in 1995.
The final outcome of this matter cannot now be determined; however, in
management's opinion, the final outcome will not have a material adverse effect
on these financial statements.
RETAIL RATEPAYERS' SUIT CONCLUDED
In March 1993, several retail ratepayers of Georgia Power filed a civil
complaint in the Superior Court of Fulton County, Georgia, against Georgia
Power, The Southern Company, the system service company, and Arthur Andersen &
Co. The complaint alleged that Georgia Power obtained excessive rate increases
by improper accounting for spare parts and sought actual damages estimated by
the plaintiffs to be in excess of $60 million -- plus treble and punitive
damages -- for alleged violations of the Georgia Racketeer Influenced and
Corrupt Organizations Act and other state statutes, statutory and common law
fraud, and negligence. These state law allegations were substantially the same
as those included in a 1989 suit brought in federal district court in Georgia.
That suit and similar ones filed in Alabama, Florida, and Mississippi federal
courts were subsequently dismissed.
The defendants' motions to dismiss the current complaint were granted by the
Superior Court of Fulton County, Georgia, in July 1993. In January 1994, the
plaintiffs' appeal of the dismissal to the Supreme Court of Georgia was
rejected. This matter is now concluded.
GULF STATES SETTLEMENT
On November 7, 1991, subsidiaries of The Southern Company entered into a
settlement agreement with Gulf States that resolved litigation between the
companies that had been pending since 1986 and arose out of a dispute over
certain unit power and long-term power sales contracts. In 1993, all remaining
terms and obligations of the settlement agreement were satisfied.
Based on the value of the settlement proceeds received, the Company recorded
increases of $3 million in 1992 and $89 million in 1991 net income.
FERC REVIEW OF EQUITY RETURNS
In May 1991, the FERC ordered that hearings be conducted concerning the
reasonableness of the Southern electric system's wholesale rate schedules and
contracts that have a return on common equity of 13.75 percent or greater. The
contracts that could be affected by the hearings include substantially all of
the transmission, unit power, long-term power, and other similar contracts.
Any changes in the rate of return on common equity that may occur as a result
of this proceeding would be effective 60 days after a proper notice of the
proceeding is published. A notice was published on May 10, 1991.
In August 1992, a FERC administrative law judge issued an opinion that
changes in rate schedules and contracts were not necessary and that the FERC
staff failed to show how any changes were in the public interest. The FERC
staff has filed exceptions to the administrative law judge's opinion, and the
matter remains pending before the FERC.
22
<PAGE> 23
NOTES (continued)
Georgia Power Company 1993 Annual Report
The final outcome of this matter cannot now be determined; however, in
management's opinion, the final outcome will not have a material adverse effect
on the Company's financial statements.
PLANT VOGTLE PHASE-IN PLANS
Pursuant to orders from the GPSC, the Company recorded a deferred return under
phase-in plans for Plant Vogtle Units 1 and 2 until October 1991 when the
allowed investment was fully reflected in rates. In addition, the GPSC issued
two separate accounting orders that required the Company to defer substantially
all operating and financing costs related to both units until rate orders
addressed these costs. These GPSC orders provide for the recovery of deferred
costs within 10 years. The GPSC modified the phase-in plans in 1991 to
accelerate the recognition of costs previously deferred under the Plant Vogtle
Unit 2 phase-in plan and to levelize the remaining Plant Vogtle declining
capacity buyback expenses.
Under these orders, the Company has deferred and begun amortizing these costs
(as recovered through rates) as follows:
<TABLE>
<CAPTION>
1993 1992 1991
(in millions)
<S> <C> <C> <C>
Deferred expenses:
Capacity buybacks $(38) $(100) $(30)
Other operating - - (7)
Amortization of previously
deferred return and
expenses 74 69 53
Deferred expenses, net 36 (31) 16
Deferred return - - 35
Less income taxes - 23 8
Net (deferral) amortization 36 (8) (11)
Effect of adoption of FASB
Statement No. 109 160 - -
Deferred costs
at beginning of year 383 375 364
Deferred costs
at end of year $507 $ 383 $375
</TABLE>
NUCLEAR PERFORMANCE STANDARDS
In October 1989, the GPSC 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 U.S.
nuclear units operating at a capacity factor of 50% or higher during the
three-year period of evaluation. Depending on the performance of the units,
the Company could receive a monetary reward or penalty under the performance
standards criteria. The first evaluation was conducted in 1993 for performance
during the 1990-92 period. During this three-year period, the Company's units
performed at an average capacity factor of 81 percent compared to an industry
average of approximately 73 percent. Based on these results, the GPSC approved
a performance reward of approximately $8.5 million for the Company. This
reward is being collected through the retail fuel cost recovery provision and
recognized in income over a 36- month period beginning November, 1993.
4. COMMITMENTS AND CONTINGENCIES
CONSTRUCTION PROGRAM
The Company is engaged in a continuous construction program and currently
estimates property additions to be approximately $688 million in 1994, $555
million in 1995 and $629 million in 1996. These estimated additions include
AFUDC of $19 million in 1994, $27 million in 1995, and $18 million in 1996.
The estimates for property additions for the three-year period include $88
million committed to meeting the requirements of the Clean Air Act.
While the Company has no new baseload generating plants under construction,
the construction of nine combustion turbine peaking units is planned to be
completed by 1996. In addition, significant construction of transmission and
distribution facilities, and upgrading and extending the useful life of
generating plants will continue. 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.
23
<PAGE> 24
NOTES (continued)
Georgia Power Company 1993 Annual Report
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 obligations were approximately $4.8 billion at
December 31, 1993. Additional commitments for coal and for nuclear fuel will
be required in the future to supply the Company's fuel needs.
OPERATING LEASES
The Company has entered into coal rail car rental agreements with various terms
and expiration dates. Rental expense totaled $8 million, $7 million, and $5
million for 1993, 1992, and 1991, respectively. Minimum annual rental
commitments for noncancellable rail car leases are $9 million annually for
years 1994 through 1998, and total approximately $191 million thereafter.
ROCKY MOUNTAIN PROJECT STATUS
In its 1985 financing order, the GPSC concluded that completion of the Rocky
Mountain pumped storage hydroelectric project 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 project. 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 project, as discussed in Note 5. The joint ownership
agreement significantly reduces the risk of the project being canceled.
However, full recovery of the Company's costs depends on the GPSC's treatment
of the project's cost and disposition of the project's capacity output. In the
event the Company cannot demonstrate to the GPSC the project's economic
viability based on current ownership, construction schedule, and costs, then
part or all of such costs may have to be written off in accordance with FASB
Statement No. 90, Accounting for Abandonments and Disallowed Plant Costs. At
December 31, 1993, the Company's investment in the project amounted to
approximately $197 million. AFUDC accrued on the Rocky Mountain project has not
been credited to income or included in the project cost since December 1985.
If accrual of AFUDC is not resumed, the Company's portion of the estimated
total plant additions at completion would be approximately $199 million. The
plant is currently scheduled to begin commercial operation in 1995.
The Company has held preliminary discussions with other parties regarding the
potential disposition of its remaining interest in the project.
The ultimate outcome of this matter cannot now be determined.
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 limits to $9.4 billion 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. A company could be assessed up to $79 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 -- based on its ownership and buyback
interests -- is $171 million per incident but not more than an aggregate of $22
million to be paid for each incident in any one year.
The Company is a member of Nuclear Mutual Limited (NML), a mutual insurer
established to provide property damage insurance in an amount up to $500
million for members' nuclear generating facilities. The members are subject to
a retrospective premium adjustment in the event that losses exceed accumulated
reserve funds. The Company's maximum assessment per incident is limited to $18
million under current policies.
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 NML
coverage. This excess insurance is provided by Nuclear Electric
24
<PAGE> 25
NOTES (continued)
Georgia Power Company 1993 Annual Report
Insurance Limited (NEIL), a mutual insurance company, and American Nuclear
Insurers/Mutual Atomic Energy Liability Underwriters.
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 21 weeks after the outage --
for one year and up to $2.3 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 maximum assessments per incident under the current policies for
the Company would be $15 million for excess property damage and $13 million for
replacement power.
For all on-site property damage insurance policies for commercial nuclear
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.
The Company participates in an insurance program for nuclear workers that
provides coverage for worker tort claims filed for bodily injury caused at
commercial nuclear power plants. In the event that claims for this insurance
exceed the accumulated reserve funds, the Company could be subject to a maximum
total assessment of $7 million.
5. FACILITY SALES AND JOINT OWNERSHIP AGREEMENTS
Since 1975, the Company has sold undivided interests in plants Hatch, Wansley,
Vogtle, and Scherer Units 1 and 2, together with transmission facilities, to
OPC, an electric membership generation and transmission corporation; the
Municipal Electric Authority of Georgia (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, an
affiliate.
Additionally, the Company has completed two of four separate transactions to
sell Unit 4 of Plant Scherer to Florida Power & Light Company (FPL) and
Jacksonville Electric Authority (JEA) for a total price of approximately $806
million, including any gains on these transactions. FPL will eventually own
approximately 76.4 percent of the unit, with JEA owning the remainder. Georgia
Power will continue to operate the unit.
The completed and scheduled remaining transactions are as follows:
<TABLE>
<CAPTION>
Closing Percent After-Tax
Date Capacity Ownership Amount Gain
(in megawatts) (in millions)
<S> <C> <C> <C> <C>
July 1991 290 35.46% $291 $14
June 1993 258 31.44 253 18
June 1994 135 16.55 132 10
June 1995 135 16.55 130 10
Total 818 100.00% $806 $52
</TABLE>
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.
As discussed in Note 4, the Company and OPC have a joint ownership
arrangement for the Rocky Mountain pumped storage hydroelectric project under
which the Company will retain its present investment in the project and OPC
will finance and complete the remainder of the project and operate the
completed facility. Based on current cost estimates the Company's ownership
will be approximately 25% of the project (194 megawatts of capacity) at
completion.
The Company will own six of eight 80 megawatt combustion turbine generating
units and 75% of the related common facilities being jointly constructed with
Savannah Electric, an affiliate. The Company's investment in the project at
December 31, 1993, was $100 million and is expected to total approximately $182
million when the project is completed. All units are
25
<PAGE> 26
NOTES (continued)
Georgia Power Company 1993 Annual Report
expected to be completed by June, 1995. Savannah Electric will operate these
units.
In connection with the joint ownership arrangements for plants Vogtle and
Scherer, the Company has made commitments to purchase declining fractions of
OPC's and MEAG's capacity and energy from these units. These commitments are
in effect during periods of up to 10 years following commercial operation (and
with regard to a portion of a 5 percent interest in Plant Vogtle owned by MEAG,
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 $183 million, $289 million and $320 million in 1993, 1992 and 1991,
respectively. The Plant Scherer buyback agreements ended in 1993. The current
projected Plant Vogtle capacity payments for the next five years are as
follows: $132 million in 1994, $77 million in 1995, $70 million in 1996, $59
million in 1997 and $59 million in 1998. 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. Additionally, the Plant Vogtle declining capacity buyback expense is
being levelized over a six-year period. See Note 3 for further information.
At December 31, 1993, the Company's percentage ownership and investment
(exclusive of nuclear fuel) in jointly owned facilities in commercial
operation, were as follows:
<TABLE>
<CAPTION>
Total Company
Facility (Type) Capacity Ownership
(megawatts)
<S> <C> <C>
Plant Vogtle (nuclear) 2,320 45.7%
Plant Hatch (nuclear) 1,630 50.1
Plant Wansley (coal) 1,779 53.5
Plant Scherer (coal)
Units 1 and 2 1,636 8.4
Unit 3 818 75.0
Unit 4 818 33.1
Accumulated
Facility (Type) Investment Depreciation
(in millions)
Plant Vogtle (nuclear) $3,285 (1) $540
Plant Hatch (nuclear) 840 325
Plant Wansley (coal) 286 125
Plant Scherer (coal)
Units 1 and 2 111 33
Unit 3 539 107
Unit 4 236 31
</TABLE>
(1) Investment net of write-offs.
The Company and an affiliate, Alabama Power, own equally all of the
outstanding capital stock of Southern Electric Generating Company (SEGCO),
which owns electric generating units with a total rated capacity of 1,020
megawatts, as well as associated transmission facilities. The capacity of the
units has been sold equally to the Company and Alabama Power under a contract
expiring in 1994, 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. An amended
contract has been filed with the FERC with substantially the same provisions,
but the term thereof would be extended automatically for two year periods,
subject to any 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
26
<PAGE> 27
NOTES (continued)
Georgia Power Company 1993 Annual Report
Income, is as follows:
<TABLE>
<CAPTION>
1993 1992 1991
(in millions)
<S> <C> <C> <C>
Energy $ 81 $ 66 $ 74
Capacity 9 9 10
Total $ 90 $ 75 $ 84
Kilowatt-hours 3,352 2,664 2,911
</TABLE>
At December 31, 1993, the capitalization of SEGCO consisted of $58 million of
equity and $84 million of long-term debt on which the annual interest
requirement is $3.8 million.
6. LONG-TERM POWER SALES AGREEMENTS
The Company and the operating affiliates of The Southern Company have entered
into long-term contractual agreements for the sale of capacity and energy to
certain non-affiliated utilities located outside the system's service
territory. Certain of these agreements are non-firm and are based on the
capacity of the Southern system. Other agreements are firm and pertain to
capacity related to 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 capacity revenues have been as
follows:
<TABLE>
<CAPTION>
Unit Power Other
Year Sales Long-Term
(in millions)
<S> <C> <C>
1993 $135 $17
1992 223 10
1991 263 11
</TABLE>
Long-term non-firm power of 400 megawatts was sold by the Southern electric
system in 1993 to Florida Power Corporation (FPC). This amount decreases to
200 megawatts in 1994 and the contract expires at year-end. Sales under these
long-term non-firm power sales agreements are made from available power pool
energy, and the revenues from the sales are shared by the operating affiliates.
Unit power from specific generating plants is being sold to FPL, JEA, and the
City of Tallahassee, Florida and beginning in 1994 to FPC. Under these
agreements, the Company sold approximately 830 megawatts of capacity in 1993
and is scheduled to sell approximately 403 megawatts of capacity in 1994.
Thereafter, these sales will decline to an estimated 157 megawatts by the end
of 1996 and will remain at that approximate level through 1999. After 2000,
capacity sales will decline to approximately 101 megawatts -- unless reduced by
FPL and JEA -- until the expiration of the contracts in 2010.
7. INCOME TAXES
Effective January 1, 1993, the Company adopted FASB Statement No. 109,
Accounting for Income Taxes. The adoption of Statement No. 109 resulted in
cumulative adjustments that had no material effect on net income. The adoption
also resulted in the recording of additional deferred income taxes and related
assets and liabilities. The related assets of $993 million are revenues to be
received from customers. These assets are attributable to tax benefits
flowed-through to customers in prior years, and taxes applicable to
capitalized AFUDC. The related liabilities of $453 million are revenues to be
refunded to customers. These liabilities are attributable to deferred taxes
previously recognized at rates higher than current enacted tax law and to
unamortized investment tax credits. Additionally, deferred income taxes
related to accelerated tax depreciation previously shown as a reduction to
utility plant were reclassified.
Details of the federal and state income tax provisions are as follows:
<TABLE>
<CAPTION>
1993 1992 1991
Total provision for income taxes: (in millions)
<S> <C> <C> <C>
Federal:
Currently payable $223 $139 $267
Deferred -
Current year 181 170 97
Reversal of prior years (40) (6) (52)
Deferred investment tax
credits (18) (6) (10)
346 297 302
State:
Currently payable 41 24 47
Deferred -
Current year 31 35 17
Reversal of prior years (3) (3) (9)
69 56 55
Total 415 353 357
Less:
Income taxes charged
(credited) to other
income (37) (25) 8
Federal and state income
taxes charged to operations $452 $378 $349
</TABLE>
27
<PAGE> 28
NOTES (continued)
Georgia Power Company 1993 Annual Report
The tax effects of temporary differences between the carrying amounts of
assets and liabilities in the financial statements and their respective tax
basis, which give rise to deferred tax assets and liabilities are as follows:
<TABLE>
<CAPTION>
1993
(in millions)
<S> <C>
Deferred tax liabilities:
Accelerated depreciation $1,458
Property basis differences 1,163
Deferred Plant Vogtle costs 161
Premium on reacquired debt 63
Fuel clause underrecovered 32
Other 62
Total 2,939
Deferred tax assets:
Other basis differences 263
Federal effect of state deferred taxes 92
Other deferred costs 61
Disallowed plant buybacks 29
Accrued interest 24
Other 12
Total 481
Net deferred tax liabilities (assets) 2,458
Portion included in current assets (22)
Accumulated deferred income taxes
in the Balance Sheets $2,480
</TABLE>
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 $19 million in 1993, $19 million in 1992, and $27 million in 1991.
At December 31, 1993, all investment tax credits available to reduce federal
income taxes payable had been utilized.
A reconciliation of the federal statutory tax rate to effective income tax
rate is as follows:
<TABLE>
<CAPTION>
1993 1992 1991
<S> <C> <C> <C>
Federal statutory rate 35% 34% 34%
State income tax, net of
federal deduction 4 4 4
Non-deductible book
depreciation 3 3 4
Difference in prior years'
deferred and current tax rate (1) (1) (1)
Other (1) (2) (1)
Effective income tax rate 40% 38% 40%
</TABLE>
The Southern Company and its subsidiaries file a consolidated federal income
tax return. Under a joint consolidated income tax agreement, each company's
current and deferred tax expense is computed on a stand-alone basis, and
consolidated tax savings are allocated to each company based on its ratio of
taxable income to total consolidated taxable income.
8. CAPITALIZATION
COMMON STOCK DIVIDEND RESTRICTIONS
The Company's first mortgage bond indenture contains various common stock
dividend restrictions that remain in effect as long as the bonds are
outstanding. At December 31, 1993, $742 million of retained earnings were
restricted against the payment of cash dividends on common stock under terms of
the mortgage indenture. Supplemental indentures in connection with future
first mortgage bond issues may contain more stringent common stock dividend
restrictions than those currently in effect.
The Company's charter limits cash dividends on common stock to the lesser of
the retained earnings balance or 75 percent of net income available for such
stock during a prior period of 12 months if the ratio of common stock equity to
total capitalization, including retained earnings, adjusted to reflect the
payment of the proposed dividend, is below 25 percent, and to 50 percent of
such net income if such ratio is less than 20 percent. At December 31, 1993,
the ratio as defined was 46.1 percent.
28
<PAGE> 29
NOTES (continued)
Georgia Power Company 1993 Annual Report
REMARKETED BONDS
In 1992, the Company issued two series of variable rate first mortgage bonds
each with principal amounts of $100 million due 2032. The current composite
interest rate on the bonds is 6.20 percent and is fixed for the first three
years of the issues.
POLLUTION CONTROL BONDS
The Company has incurred obligations in connection with the sale by public
authorities of tax-exempt pollution control and industrial development revenue
bonds. The Company has authenticated and delivered to trustees an aggregate of
$407.7 million of its first mortgage bonds, which are pledged as security for
its obligations under pollution control and industrial development contracts.
No interest on these first mortgage bonds is payable unless and until a default
occurs on the installment purchase or loan agreements. An aggregate of
approximately $1.3 billion of the pollution control and industrial development
bonds is secured by a subordinated interest in specific property of the
Company.
Details of pollution control bonds are as follows:
<TABLE>
<CAPTION>
Maturity Interest Rates 1993 1992
(in millions)
<S> <C> <C> <C>
2003-2007 5.70% to 6.75% $ 90 $ 103
2008-2011 6.375% & Variable 19 32
2014-2018 6.00% to 12.25% 1,237 1,283
2019-2023 5.75% to 7.25% &
Variable 315 243
Total pollution control bonds $ 1,661 $ 1,661
</TABLE>
BANK CREDIT ARRANGEMENTS
At the beginning of 1994, the Company had unused credit arrangements with banks
totaling $540 million, of which $10 million expires June 30, 1994, $130
million expires at May 1, 1996, and $400 million expires at June 30, 1996.
The $400 million expiring June 30, 1996, is under revolving credit
arrangements with several banks providing the Company, Alabama Power, and The
Southern Company up to a total credit amount of $400 million. To provide
liquidity support for commercial paper programs and for other short-term cash
needs, $165 million and $135 million of the $400 million available credit are
currently dedicated for the Company and Alabama Power, respectively. However,
the allocations can be changed among the borrowers by notifying the respective
banks.
During the term of the agreements expiring in 1996, short-term borrowings may
be converted into term loans, payable in 12 equal quarterly installments, with
the first installment due at the end of the first calendar quarter after the
applicable termination date or at an earlier date at the companies' option. In
addition, these agreements require payment of commitment fees based on the
unused portions of the commitments or the maintenance of compensating balances
with the banks.
The $10 million credit arrangement expiring in 1994 allows borrowings for up
to 90 days. Commitment fees are based on the unused portion of the commitment.
In addition, the Company borrows under uncommitted lines of credit with banks
and through a $150 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 1993.
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, 1993, the Company had a capitalized lease
obligation for its corporate headquarters building of $88 million with an
interest rate of 8.1 percent. Other capitalized lease obligations were $137
thousand with a composite interest rate of 6.8 percent.
The maturities of capital lease obligations through 1998 are approximately as
follows: $423 thousand in 1994, $309 thousand in 1995, $335 thousand in 1996,
$362 thousand in 1997, and $392 thousand in 1998.
The lease agreement for the corporate headquarters building 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
29
<PAGE> 30
NOTES (continued)
Georgia Power Company 1993 Annual Report
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, 1993,
and 1992, the interest and lease amortization deferred on the Balance Sheets
are $47 million and $48 million, respectively.
In December 1993, the Company borrowed $37 million through a long-term note
due in 1995.
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.
LONG-TERM DEBT DUE WITHIN ONE YEAR
The current portion of the Company's long-term debt is as follows:
<TABLE>
<CAPTION>
1993 1992
(in millions)
<S> <C> <C>
First mortgage bonds:
Redemption of 10.75% issue due 2018 $ - $3.7
Redemption of variable rate issue due
2020 - 50.0
Improvement fund requirement - 30.4
Pollution control bonds
5.95% series sinking fund requirement - 0.3
6.4% series sinking fund requirement * 0.2
6.75% series sinking fund requirement * -
6.375% series sinking fund requirement * -
Other long-term debt 10.5 11.2
Total $10.5 $95.8
</TABLE>
*Less than .1 million
The indenture's first mortgage bond improvement fund requirement 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 depositing
cash or reacquired bonds, or by pledging additional property equal to 1 2/3
times the requirement. The 1993 and 1992 requirements were met in the first
quarter of each year by depositing cash subsequently used to redeem bonds. The
1994 requirement was funded in December 1993.
REDEMPTION OF HIGH-COST SECURITIES
The Company plans to continue a program of redeeming or replacing high-cost
debt and preferred stock in cases where opportunities exist to reduce financing
costs. High-cost 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 and sinking fund requirements, to meet
replacement provisions of the mortgage, or by use of proceeds from the sale of
property pledged under the mortgage. In general, for the first five years a
series is outstanding the Company is prohibited from redeeming for improvement
fund purposes more than 1 percent annually of the original issue amount.
9. QUARTERLY FINANCIAL DATA (UNAUDITED):
Summarized quarterly financial information for 1993 and 1992 is as follows:
<TABLE>
<CAPTION>
Net Income
After
Dividends on
Operating Operating Preferred
Quarter Ended Revenues Income Stock
(in millions)
<S> <C> <C> <C>
MARCH 1993 $1,004 $221 $108
JUNE 1993 1,096 219 141
SEPTEMBER 1993 1,376 356 245
DECEMBER 1993 975 176 76
March 1992 $ 957 $211 $ 91
June 1992 1,068 235 116
September 1992 1,280 342 227
December 1992 992 197 87
</TABLE>
The Company's business is influenced by seasonal weather conditions and the
timing of rate increases.
30
<PAGE> 31
SELECTED FINANCIAL AND OPERATING DATA
Georgia Power Company 1993 Annual Report
<TABLE>
<CAPTION>
1993 1992 1991
<S> <C> <C> <C>
OPERATING REVENUES (IN THOUSANDS) $ 4,451,181 $ 4,297,436 $ 4,301,428
NET INCOME AFTER DIVIDENDS
ON PREFERRED STOCK (IN THOUSANDS) $ 569,853 $ 520,538 $ 474,855
CASH DIVIDENDS ON COMMON STOCK (IN THOUSANDS) $ 402,400 $ 384,000 $ 375,200
RETURN ON AVERAGE COMMON EQUITY (PERCENT) 14.37 13.60 12.76
TOTAL ASSETS (IN THOUSANDS) $13,736,110 $10,964,442 $10,842,538
GROSS PROPERTY ADDITIONS (IN THOUSANDS) $ 674,432 $ 508,444 $ 548,051
CAPITALIZATION (IN THOUSANDS):
Common stock equity $ 4,045,458 $ 3,888,237 $ 3,766,551
Preferred stock 692,787 692,792 607,796
Preferred stock subject to mandatory redemption - 6,250 118,750
Long-term debt 4,031,387 4,131,016 4,553,189
Total (excluding amounts due within one year) $ 8,769,632 $ 8,718,295 $ 9,046,286
CAPITALIZATION RATIOS (PERCENT):
Common stock equity 46.1 44.6 41.7
Preferred stock 7.9 8.0 8.0
Long-term debt 46.0 47.4 50.3
Total (excluding amounts due within one year) 100.0 100.0 100.0
FIRST MORTGAGE BONDS (IN THOUSANDS):
Issued 1,135,000 975,000 -
Retired 1,337,822 1,381,300 598,384
PREFERRED STOCK (IN THOUSANDS):
Issued 175,000 195,000 100,000
Retired 245,005 165,004 100,000
SECURITY RATINGS:
First Mortgage Bonds -
Moody's A3 A3 Baa1
Standard and Poor's A- A- BBB+
Duff & Phelps A+ A- BBB+
Preferred Stock -
Moody's baa1 baa1 baa1
Standard and Poor's BBB+ BBB+ BBB
Duff & Phelps A- BBB BBB-
CUSTOMERS (YEAR-END):
Residential 1,441,972 1,421,175 1,397,682
Commercial 188,820 183,784 179,933
Industrial 11,217 11,479 11,946
Other 2,322 2,269 2,190
Total 1,644,331 1,618,707 1,591,751
EMPLOYEES (YEAR-END) 12,528 12,600 13,700
</TABLE>
31
<PAGE> 32
SELECTED FINANCIAL AND OPERATING DATA
Georgia Power Company 1993 Annual Report
<TABLE>
<CAPTION>
1990 1989 1988 1987 1986 1985 1984 1983
<S> <C> <C> <C> <C> <C> <C> <C>
$ 4,445,809 $ 4,145,240 $ 3,897,479 $ 3,786,485 $ 3,561,603 $ 3,609,140 $ 3,319,699 $ 2,869,883
$ 208,066 $ 449,099 $ 479,532 $ 240,057 $ 535,003 $ 493,717 $ 421,719 $ 304,555
$ 389,600 $ 394,500 $ 386,600 $ 377,800 $ 325,500 $ 277,500 $ 225,500 $ 189,600
5.52 11.72 13.06 6.85 16.51 17.95 18.43 15.86
$11,176,619 $11,372,346 $11,130,539 $11,197,494 $10,465,063 $ 9,030,618 $ 7,880,072 $ 6,746,247
$ 558,727 $ 727,631 $ 929,019 $ 1,034,059 $ 1,598,309 $ 1,384,182 $ 1,396,846 $ 1,015,274
$ 3,673,913 $ 3,860,657 $ 3,806,070 $ 3,538,182 $ 3,469,201 $ 3,013,707 $ 2,486,172 $ 2,089,171
607,796 607,844 657,844 657,844 732,844 632,844 482,844 432,844
125,000 155,000 162,500 166,250 112,500 120,000 127,500 131,250
5,000,225 5,054,001 4,861,378 4,825,760 4,464,857 3,878,066 3,432,606 3,128,500
$ 9,406,934 $ 9,677,502 $ 9,487,792 $ 9,188,036 $ 8,779,402 $ 7,644,617 $ 6,529,122 $ 5,781,765
39.1 39.9 40.1 38.5 39.5 39.4 38.1 36.1
7.8 7.9 8.6 9.0 9.6 9.9 9.3 9.8
53.1 52.2 51.3 52.5 50.9 50.7 52.6 54.1
100.0 100.0 100.0 100.0 100.0 100.0 100.0 100.0
300,000 250,000 150,000 500,000 500,000 - 150,000 125,000
91,117 91,516 206,677 217,949 377,538 17,738 26,084 18,273
- - - 125,000 100,000 150,000 50,000 -
83,750 7,500 3,750 150,000 7,500 3,750 2,380 4,378
Baa1 Baa2 Baa2 Baa2 Baa1 Baa1 Baa1 Baa1
BBB+ BBB+ BBB BBB BBB+ BBB+ BBB+ BBB+
BBB BBB 9 9 9 9 8 8
baa1 baa2 baa2 baa2 baa1 baa1 baa1 baa1
BBB BBB BBB- BBB- BBB BBB BBB BBB
BBB- BBB- 10 10 10 10 9 9
1,378,888 1,355,211 1,329,173 1,303,721 1,268,983 1,231,140 1,189,670 1,154,953
178,391 177,814 174,147 169,014 162,258 155,399 148,536 142,305
12,115 12,311 12,353 12,307 12,315 12,309 12,276 12,109
2,114 2,050 1,993 1,858 1,816 1,789 1,753 1,696
1,571,508 1,547,386 1,517,666 1,486,900 1,445,372 1,400,637 1,352,235 1,311,063
13,746 13,900 15,110 14,924 14,773 14,947 14,562 14,535
</TABLE>
32
<PAGE> 33
SELECTED FINANCIAL AND OPERATING DATA (continued)
Georgia Power Company 1993 Annual Report
<TABLE>
<CAPTION>
1993 1992 1991
<S> <C> <C> <C>
OPERATING REVENUES (IN THOUSANDS):
Residential $ 1,291,035 $ 1,128,396 $ 1,111,358
Commercial 1,354,130 1,285,681 1,243,067
Industrial 1,113,067 1,083,856 1,057,702
Other 41,399 39,504 37,861
Total retail 3,799,631 3,537,437 3,449,988
Sales for resale - non-affiliates 534,370 640,308 736,643
Sales for resale - affiliates 61,668 67,835 65,586
Total revenues from sales of electricity 4,395,669 4,245,580 4,252,217
Other revenues 55,512 51,856 49,211
Total $ 4,451,181 $ 4,297,436 $ 4,301,428
KILOWATT-HOUR SALES (IN THOUSANDS):
Residential 16,649,859 14,939,172 14,815,089
Commercial 18,278,508 17,260,614 16,885,833
Industrial 23,635,363 22,978,312 22,298,062
Other 460,801 436,144 429,016
Total retail 59,024,531 55,614,242 54,428,000
Sales for resale - non-affiliates 14,307,030 15,870,222 18,719,924
Sales for resale - affiliates 3,027,733 3,320,060 3,885,892
Total 76,359,294 74,804,524 77,033,816
AVERAGE REVENUE PER KILOWATT-HOUR (CENTS):
Residential 7.75 7.55 7.50
Commercial 7.41 7.45 7.36
Industrial 4.71 4.72 4.74
Total retail 6.44 6.36 6.34
Sales for resale 3.44 3.69 3.55
Total sales 5.76 5.68 5.52
RESIDENTIAL AVERAGE ANNUAL KILOWATT-HOUR USE PER
CUSTOMER 11,630 10,603 10,675
RESIDENTIAL AVERAGE ANNUAL REVENUE PER CUSTOMER $ 901.79 $ 800.88 $ 800.78
PLANT NAMEPLATE CAPACITY RATINGS (YEAR-END)
(MEGAWATTS) 13,759 14,076 14,076
MAXIMUM PEAK-HOUR DEMAND (MEGAWATTS) (NOTE):
Winter 9,067 8,938 10,001
Summer 12,573 11,448 13,090
ANNUAL LOAD FACTOR (PERCENT) 58.5 60.5 55.2
PLANT AVAILABILITY (PERCENT):
Fossil-steam 85.9 86.6 93.3
Nuclear 85.5 87.7 81.6
SOURCE OF ENERGY SUPPLY (PERCENT):
Coal 62.1 61.4 63.6
Nuclear 16.2 17.0 15.3
Hydro 2.3 2.5 2.3
Oil and gas 0.2 * *
Purchased power -
From non-affiliates 10.2 12.2 10.3
From affiliates 9.0 6.9 8.5
Total 100.0 100.0 100.0
TOTAL FUEL ECONOMY DATA:
BTU per net kilowatt-hour generated 9,912 9,900 9,960
Cost of fuel per million BTU (cents) 153.62 153.08 157.97
Average cost of fuel per net kilowatt-hour
generated (cents) 1.52 1.52 1.57
</TABLE>
Note: As of 9/1/91, Georgia Power Company's sales to Oglethorpe Power Company
are not included in Peak-Hour Demand
* Less than one-tenth of one percent.
33
<PAGE> 34
SELECTED FINANCIAL AND OPERATING DATA (continued)
Georgia Power Company 1993 Annual Report
<TABLE>
<CAPTION>
1990 1989 1988 1987 1986 1985 1984 1983
<S> <C> <C> <C> <C> <C> <C> <C>
$ 1,109,165 $ 1,022,781 $ 979,047 $ 904,218 $ 874,231 $ 786,500 $ 754,163 $ 686,269
1,218,441 1,143,727 1,054,995 915,540 854,755 797,540 739,035 649,932
1,061,830 1,006,416 983,822 911,933 897,646 873,554 858,536 747,305
36,773 34,775 31,743 29,350 27,948 26,766 24,388 20,972
3,426,209 3,207,699 3,049,607 2,761,041 2,654,580 2,484,360 2,376,122 2,104,478
784,086 760,809 707,076 822,696 780,049 941,743 779,028 666,739
168,251 150,394 86,751 159,998 91,753 149,463 136,047 70,784
4,378,546 4,118,902 3,843,434 3,743,735 3,526,382 3,575,566 3,291,197 2,842,001
67,263 26,338 54,045 42,750 35,221 33,574 28,502 27,882
$ 4,445,809 $ 4,145,240 $ 3,897,479 $ 3,786,485 $ 3,561,603 $3,609,140 $3,319,699 $2,869,883
14,771,648 14,134,195 13,800,038 13,675,730 13,234,248 12,006,462 11,548,787 11,443,257
16,627,128 15,843,181 14,790,561 13,799,379 12,945,926 11,945,938 10,902,163 10,181,953
22,126,604 21,801,404 21,412,845 20,884,454 20,339,235 19,517,543 18,862,531 17,415,441
428,459 414,107 397,669 385,514 381,917 382,238 342,047 331,804
53,953,839 52,192,887 50,401,113 48,745,077 46,901,326 43,852,181 41,655,528 39,372,455
20,158,681 20,479,412 18,544,705 20,910,185 18,198,186 21,526,865 19,138,575 16,197,259
8,272,528 7,489,948 3,327,814 6,032,889 3,160,242 5,999,834 4,970,928 2,938,120
82,385,048 80,162,247 72,273,632 75,688,151 68,259,754 71,378,880 65,765,031 58,507,834
7.51 7.24 7.09 6.61 6.61 6.55 6.53 6.00
7.33 7.22 7.13 6.63 6.60 6.68 6.78 6.38
4.80 4.62 4.59 4.37 4.41 4.48 4.55 4.29
6.35 6.15 6.05 5.66 5.66 5.67 5.70 5.35
3.35 3.26 3.63 3.65 4.08 3.96 3.80 3.85
5.31 5.14 5.32 4.95 5.17 5.01 5.00 4.86
10,795 10,530 10,484 10,623 10,577 9,923 9,855 10,049
$ 810.56 $ 761.96 $ 743.82 $ 702.36 $ 698.72 $ 650.01 $ 643.53 $ 602.66
14,366 14,366 13,018 13,018 11,875 11,875 11,767 11,698
8,977 10,101 9,866 9,446 10,551 10,049 8,462 7,556
13,196 12,735 12,295 12,390 11,910 11,079 10,443 10,933
55.5 56.3 59.1 56.1 57.5 56.3 56.9 51.9
92.5 93.0 94.5 92.7 91.2 91.2 91.0 91.7
81.3 89.2 69.4 85.4 64.7 79.5 47.3 68.6
65.1 64.0 72.0 70.9 74.6 72.7 74.4 72.2
13.7 14.1 9.6 9.1 5.0 6.7 4.0 6.3
2.2 2.1 1.2 1.7 1.2 1.5 2.7 3.1
0.1 0.1 0.1 0.1 0.6 * * 0.1
11.0 10.2 8.2 8.5 8.9 9.4 9.2 8.4
7.9 9.5 8.9 9.7 9.7 9.7 9.7 9.9
100.0 100.0 100.0 100.0 100.0 100.0 100.0 100.0
9,939 10,020 9,969 9,932 10,016 10,089 10,002 10,100
166.22 164.27 166.28 168.81 175.81 178.11 184.63 179.92
1.65 1.65 1.66 1.68 1.76 1.80 1.85 1.82
</TABLE>
34
