<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
-----------------
THE SOUTHERN COMPANY
- ----------------------------------------------------------------------------
(Exact name of registrant as specified in its charter)
Delaware 1-3526 58-0690070
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(State or other jurisdiction (Commission (IRS Employer
of incorporation) File Number) Identification No.)
64 Perimeter Center East, Atlanta, Georgia 30346
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(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code (404) 393-0650
--------------
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.
(c) Exhibits.
23 - Consent of Arthur Andersen & Co.
99 - Audited Financial Statements of The Southern
Company as of December 31, 1993.
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.
THE SOUTHERN COMPANY
By /s/ W. Dean Hudson
----------------------
W. Dean Hudson
Comptroller
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 The
Southern Company's previously filed Registration Statement File Nos. 2-78617,
33-3546, 33-23152, 33-30171, 33-23153 and 33-51433.
/s/ Arthur Andersen & Co.
-------------------------
ARTHUR ANDERSEN & CO.
Atlanta, Georgia
March 1, 1994
<PAGE> 1
EXHIBIT 99
MANAGEMENT'S REPORT
The Southern Company and Subsidiary Companies 1993 Annual Report
The management of The Southern Company has prepared -- and is responsible for
- -- the consolidated financial statements and related information included in
this report. 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 books and records
reflect only authorized transactions of the company. Limitations exist in any
system of internal controls, however, based on a recognition that the cost of
the system should not exceed its benefits. The company believes 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, composed of three directors
who are not employees, provides a broad overview of management's financial
reporting and control functions. Periodically, 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 controls, and financial reporting matters. The internal
auditors and 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 according to a high
standard of business ethics.
In management's opinion, the consolidated financial statements present
fairly, in all material respects, the financial position, results of
operations, and cash flows of The Southern Company and its subsidiaries 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 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/ E. L. Addison /s/ W. L. Westbrook
- ------------------------------------ ----------------------------
Edward L. Addison W. L. Westbrook
Chairman and Chief Executive Officer Financial Vice President
<PAGE> 2
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
The Southern Company and Subsidiary Companies 1993 Annual Report
TO THE BOARD OF DIRECTORS AND TO THE STOCKHOLDERS OF THE SOUTHERN COMPANY:
We have audited the accompanying consolidated balance sheets and consolidated
statements of capitalization of The Southern Company (a Delaware corporation)
and its subsidiaries as of December 31, 1993 and 1992, and the related
consolidated 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 11-32) referred to above
present fairly, in all material respects, the financial position of The
Southern Company and its subsidiaries as of December 31, 1993 and 1992, and the
results of their operations and their cash flows for the periods stated, in
conformity with generally accepted accounting principles.
As explained in Notes 2 and 9 to the financial statements, effective January
1, 1993, The Southern 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
recoverability of the 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
The Southern Company and Subsidiary Companies 1993 Annual Report
RESULTS OF OPERATIONS
EARNINGS AND DIVIDENDS
The Southern Company's 1993 financial performance exceeded the strong results
recorded for 1992, and set several new records. The company's financial
strength continued to gain momentum for the third consecutive year. In January
1994, The Southern Company board of directors increased the quarterly dividend
rate by 3.5 percent, and approved a two-for-one common stock split in the form
of a stock distribution. For all reported common stock data, the number of
common shares outstanding and per share amounts for earnings, dividends, and
market price have been adjusted to reflect the stock distribution. For 1993,
The Southern Company's net income of $1.0 billion established a new record high
and the company's common stock reached an all-time high closing price during
the year of 23 3/8 -- surpassing the record of 19 1/2 set in 1992. Also,
return on average common equity reached the highest level since 1986.
Earnings reported for 1993 totaled $1,002 million or $1.57 per share, an
increase of $49 million or 6 cents per share from the previous year. Both 1993
and 1992 earnings were affected by special non-operating or non-recurring
items. After excluding these special items in both years, earnings from
operations of the ongoing business of selling electricity were $1,016 million
or $1.59 per share, an increase of $77 million or 10 cents per share compared
with 1992. The special items that affected 1993 and 1992 earnings were as
follows:
<TABLE>
<CAPTION>
Consolidated Earnings
Net Income Per Share
1993 1992 1993 1992
(in millions)
<S> <C> <C> <C> <C>
Earnings as reported $1,002 $953 $1.57 $1.51
Gulf States related (6) (16) (.01) (.03)
Sale of Scherer Unit 4 (18) -- (.03) --
Environmental
cleanup 25 2 .04 .01
Transportation fleet
reductions 13 -- .02 --
Total items excluded 14 (14) .02 (.02)
Earnings from
operations $1,016 $939 $1.59 $1.49
Amount and
percent change $77 8.2% $0.10 6.7%
</TABLE>
In 1993, several items -- both positive and negative -- had an impact on
earnings, which resulted in a net reduction of $14 million. These items were:
(1) The conclusion of a settlement agreement -- discussed later -- with Gulf
States Utilities (Gulf States) increased earnings. (2) The second in a series
of four separate transactions to sell Plant Scherer Unit 4 to two Florida
utilities increased earnings. (3) Environmental clean-up costs incurred at
sites located in Alabama and Georgia decreased earnings. (4) Costs associated
with a transportation fleet reduction program decreased earnings. The
improvements in 1993 earnings resulted primarily from increased retail energy
sales and continued emphasis on effective cost controls.
The special items that increased 1992 earnings were primarily related to
additional settlement provisions from Gulf States, and to gains on the sale of
Gulf States common stock received in 1991.
Returns on average common equity were 13.43 percent in 1993, 13.42 percent
in 1992, and 12.74 percent in 1991. Dividends paid on common stock during 1993
were $1.14 per share or 28 1/2 cents per quarter. During 1992 and 1991,
dividends paid per share were $1.10 and $1.07, respectively. In January 1994,
The Southern Company board of directors raised the quarterly dividend to 29 1/2
cents per share or an annual rate of $1.18 per share.
REVENUES
Operating revenues increased in 1993 and 1992 and decreased in 1991 as a result
of the following factors:
<TABLE>
<CAPTION>
Increase (Decrease)
From Prior Year
1993 1992 1991
(in millions)
<S> <C> <C> <C>
Retail --
Change in base rates $ 3 $ 137 $ 46
Sales growth 104 138 122
Weather 198 (113) (19)
Fuel cost recovery
and other 199 (55) (36)
Total retail 504 107 113
Sales for resale --
Within service area 38 (8) 5
Outside service area (184) (87) (93)
Total sales for resale (146) (95) (88)
Other operating revenues 58 11 (28)
Total operating revenues $ 416 $ 23 $ (3)
Percent change 5.2% 0.3% 0.0%
</TABLE>
3
<PAGE> 4
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
The Southern Company and Subsidiary Companies 1993 Annual Report
Retail revenues of $7.3 billion in 1993 increased 7.4 percent from last
year, compared with an increase of 1.6 percent in 1992. Under fuel cost
recovery provisions, fuel revenues generally equal fuel expense -- including
the fuel component of purchased energy -- and do not affect net income.
Sales for resale revenues within the service area were $447 million in 1993,
up 9.2 percent from the prior year. This increase resulted primarily from the
prolonged hot summer weather, which increased the demand for electricity.
Revenues from sales for resale within the service area were $409 million in
1992, down 1.9 percent from the prior year. The decrease resulted from certain
municipalities and cooperatives in the service area retaining more of their own
generation at facilities jointly owned with Georgia Power.
Revenues from sales to 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 $350 $457 $490
Energy 230 330 366
Total $580 $787 $856
</TABLE>
Capacity revenues decreased in 1993 and 1992 because the amount of capacity
under contract declined by some 500 megawatts and 300 megawatts, respectively.
In 1994, the contracted capacity will decline another 400 megawatts.
Changes in revenues are influenced heavily by the amount of energy sold each
year. Kilowatt-hour sales for 1993 and the percent change by year were as
follows:
<TABLE>
<CAPTION>
(billions of Amount Percent Change
kilowatt-hours) 1993 1993 1992 1991
<S> <C> <C> <C> <C>
Residential 36.8 9.5% 0.0% 1.5%
Commercial 32.8 5.9 2.1 2.4
Industrial 48.7 1.9 3.8 0.2
Other 0.9 4.6 (4.8) 1.2
Total retail 119.2 5.3 2.1 1.2
Sales for resale --
Within service area 13.3 9.5 (1.7) 10.7
Outside service area 12.4 (25.2) (16.2) (18.7)
Total 144.9 2.1 (0.7) (1.4)
</TABLE>
The rate of growth in 1993 retail energy sales was the highest since 1986.
Residential energy sales registered the highest annual increase in two decades
as a result of hotter-than-normal summer weather and the addition of 46,000 new
customers. Commercial sales were also affected by the warm summer. Industrial
energy sales in 1993 and 1992 showed moderate growth, reflecting a recovery in
the business and economic conditions in The Southern Company's service area.
Energy sales to retail customers are projected to grow at an average annual
rate of 1.7 percent during the period 1994 through 2004.
Energy sales for resale outside the service area are predominantly unit
power sales under long-term contracts to Florida utilities. Economy sales and
amounts sold under short-term contracts are also sold for resale outside the
service area. Sales to customers outside the service area have decreased for
the third consecutive year primarily as a result of the scheduled decline in
megawatts of capacity under contract. In addition, the decline in 1992 and
1991 sales was also influenced by fluctuations in prices for oil and natural
gas, the primary fuel sources for utilities with which the company has
long-term contracts. When oil and gas prices fall below a certain level, these
customers can generate electricity to meet their requirements more
economically. However, the fluctuation in these energy sales, excluding the
impact of contractual declines, had minimal effect on earnings because The
Southern Company is paid for dedicating specific amounts of its generating
capacity to these utilities.
EXPENSES
Total operating expenses of $6.7 billion for 1993 were up 6.5 percent compared
with the prior year. The increase was attributable to higher production
expenses of $75 million to meet increased energy demands and an additional $50
million in depreciation expenses and property taxes resulting from additional
utility plant being placed into service. The transportation fleet reduction
program and environmental clean-up costs discussed earlier increased expenses
by some $62 million. Also, a $67 million change in deferred Plant Vogtle
expenses compared with the amount in 1992 contributed to the rise in total
operating expenses.
In 1992, total operating expenses of $6.3 billion were at the same level
reported for 1991. The costs to produce and deliver electricity in 1992
declined by $165 million primarily as a result of less energy being sold and
continued effective cost controls. However, expenses in 1991 were reduced by
proceeds from a settlement
4
<PAGE> 5
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
The Southern Company and Subsidiary Companies 1993 Annual Report
agreement with Gulf States that more than offset the decline in 1992 expenses
when compared with 1991. Deferred expenses related to Plant Vogtle in 1992
increased by $47 million when compared with the prior year.
Fuel costs constitute the single largest expense for The Southern Company.
The mix of fuel sources for generation of electricity is determined primarily
by system load, the unit cost of fuel consumed, and the availability of hydro
and nuclear generating units. The amount and sources of generation and the
average cost of fuel per net kilowatt-hour generated were as follows:
<TABLE>
<CAPTION>
1993 1992 1991
<S> <C> <C> <C>
Total generation
(billions of kilowatt-hours) 144 140 142
Sources of generation
(percent) --
Coal 78 77 77
Nuclear 17 17 17
Hydro 4 5 5
Oil and gas 1 1 1
Average cost of fuel per net
kilowatt-hour generated
(cents) --
Coal 1.90 1.86 1.91
Nuclear 0.54 0.54 0.66
Oil and gas 4.34 4.81 2.84
Total 1.67 1.62 1.69
</TABLE>
Fuel and purchased power expenses of $2.6 billion in 1993 increased 1.3
percent compared with the prior year because of increased energy demands and
slightly higher average cost of fuel per net kilowatt-hour generated. Fuel and
purchased power costs in 1992 decreased $137 million or 5.0 percent compared
with 1991 primarily because 1.1 billion fewer kilowatt-hours were needed to
meet customer requirements. Also, the decrease in these costs was attributable
to a lower average cost of fuel per net kilowatt-hour generated.
Income taxes for 1993 increased $69 million compared with the prior year.
The increase is attributable to a number of factors, including a 1 percent
increase in the corporate federal income tax rate effective January 1993, the
second sale of additional ownership interest in Plant Scherer Unit 4, and the
increase in taxable income from operations. For 1992, income taxes rose $11
million or 1.7 percent above the amount reported for 1991.
For the fifth consecutive year, total gross interest charges and preferred
stock dividends declined from amounts reported in the previous year. The
declines are attributable to lower interest rates and significant refinancing
activities during the past two years. In 1993, these costs were $831 million
- -- down $21 million or 2.3 percent. These costs for 1992 decreased $71
million. As a result of favorable market conditions during 1993, some $3.0
billion of senior securities was issued for the primary purpose of retiring
higher-cost debt and preferred stock.
EFFECTS OF INFLATION
The Southern 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
Southern Company because of the large investment in long-lived utility plant.
Conventional accounting for historical cost does not recognize this economic
loss nor the partially offsetting gain that arises through financing facilities
with fixed-money obligations such as long-term debt and preferred 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 potential. The level of future earnings depends
on numerous factors ranging from growth in energy sales to regulatory matters.
Georgia Power has completed two 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,
Georgia Power could realize an after-tax gain currently estimated to total
approximately $20 million. See Note 7 to the financial statements for
additional information.
In early 1994, Georgia Power and the system service company announced work
force reduction programs that are estimated to reduce 1994 earnings by some $55
million. These actions will assist in efforts to control the growth in
operating expenses.
5
<PAGE> 6
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
The Southern Company and Subsidiary Companies 1993 Annual Report
See Note 4 to the financial statements for information on an uncertainty
regarding full recovery of an investment in the Rocky Mountain pumped storage
hydroelectric project.
Future earnings in the near term will depend upon growth in energy sales,
which are subject to a number of factors. Traditionally, these factors 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. However, 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 for electric utilities. The
law also includes provisions to streamline the licensing process for new
nuclear plants. The Southern Company is preparing to meet the challenge of
this major change in the traditional business practices of selling electricity.
The Energy Act allows independent power producers (IPPs) to access a utility's
transmission network in order to sell electricity to other utilities, and this
may enhance the incentive for IPPs to build cogeneration plants for a utility's
large industrial and commercial customers and sell excess energy generation to
other utilities. Although the Energy Act does not require transmission access
to retail customers, pressure for legislation to allow retail wheeling will
continue. If The Southern Company does not remain a low-cost producer and
provide quality service, the company's retail energy sales growth, as well as
new long-term contracts for energy sales outside the service area, could be
limited, and this could significantly erode earnings.
An important part of the Energy Act was to amend the Public Utility Holding
Company Act of 1935 (PUHCA) and allow holding companies to form exempt
wholesale generators and foreign utility companies to sell power largely free
of regulation under PUHCA. These new entities are able to sell power to
affiliates -- under certain restrictions -- and to own and operate power
generating facilities in other domestic and international markets. To take
advantage of these opportunities, Southern Electric International (Southern
Electric) -- founded in 1981 -- is focusing on international and domestic
cogeneration, the independent power market, and the privatization of generating
facilities in the international market. During 1993, investments of some $315
million were made in entities that own and operate generating facilities in
various international markets. In the near term, Southern Electric is expected
to have minimal effect on earnings, but the possibility exists that it could
be a prime contributor to future earnings growth.
Demand-side options -- programs that enable customers to lower or alter
their peak energy requirements -- have been implemented by some of the system
operating companies and are a significant part of integrated resource planning.
See Note 3 to the financial statements under "Georgia Power's Demand-Side
Conservation Programs" for information concerning the recovery of certain
costs. Customers can receive cash incentives for participating in these
programs as well as reduce their energy requirements. Expansion and increased
utilization of these programs will be contingent upon sharing of cost savings
between the customers and the utility. Besides promoting energy efficiency,
another benefit of these programs could be the ability to defer the need to
construct baseload generating facilities further into the future. The ability
to defer major construction projects in conjunction with precertification
approval processes of such projects by the respective state public service
commissions in Alabama, Georgia, and Mississippi will diminish the possible
exposure to prudency disallowances and the resulting impact on earnings. In
addition, Georgia Power has conducted a competitive bidding process for
additional peaking capacity needed in 1996 and 1997. To meet expected
requirements for 1996, Georgia Power has filed a plan with the state public
service commission for certification of a four-year purchase power contract and
for an ownership interest in a combustion turbine peaking unit.
Rates to retail customers served by the system operating companies are
regulated by the respective state public service commissions in Alabama,
Florida, Georgia, and Mississippi. Rates for Alabama Power and Mississippi
Power are adjusted periodically within certain limitations based on earned
retail rate of return compared with an allowed return. See Note 3 to the
financial statements for information about other regulatory matters.
The Federal Energy Regulatory Commission (FERC) regulates wholesale rate
schedules and power sales contracts that The Southern Company has with its
sales for resale customers. The FERC currently is reviewing the rate of return
on common equity included in some of these schedules and contracts and may
require such returns to be lowered, possibly retroactively. See Note 3 to the
financial statements under "FERC Reviews Equity Returns" for additional
information.
Compliance costs related to the Clean Air Act Amendments of 1990 (Clean Air
Act) could reduce earnings if such costs are not fully recovered. The Clean
Air Act is discussed later under "Environmental Matters."
6
<PAGE> 7
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
The Southern Company and Subsidiary Companies 1993 Annual Report
NEW ACCOUNTING STANDARDS
The Financial Accounting Standards Board (FASB) issued Statement No. 112,
Employers' Accounting for Postemployment Benefits, which must be effective 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 Southern
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 is effective in 1994. Statement No. 115
supersedes FASB Statement No. 12, Accounting for Certain Marketable Securities.
The Southern Company adopted the new rules January 1, 1994, with no material
effect on the financial statements.
FINANCIAL CONDITION
OVERVIEW
The Southern Company's financial condition is now the strongest since the
mid-1980s. Record levels of performance were set in 1993 related to earnings,
market price of common stock, and energy sold to retail customers. In January
1994, The Southern Company board of directors increased the common stock
dividend for the third consecutive year, and approved a two-for-one common
stock split in the form of a stock distribution.
Another major change in The Southern Company's financial condition was gross
property additions of $1.4 billion to utility plant. The majority of funds
needed for gross property additions since 1990 have been provided from
operating activities, principally from earnings and non-cash charges to income
such as depreciation and deferred income taxes. The Consolidated Statements of
Cash Flows provide additional details.
On January 1, 1993, The Southern Company changed its methods of accounting
for postretirement benefits other than pensions and for income taxes. See
notes 2 and 9 to the financial statements, regarding the impact of these
changes.
CAPITAL STRUCTURE
The company achieved a ratio of common equity to total capitalization --
including short-term debt -- of 43.5 percent in 1993, compared with 42.8
percent in 1992 and 41.5 percent in 1991. The company's goal is to maintain
the common equity ratio generally within a range of 40 percent to 45 percent.
During 1993, the operating companies sold $2.2 billion of first mortgage
bonds and, through public authorities, $385 million of pollution control
revenue bonds, at a combined weighted interest rate of 6.5 percent. Preferred
stock of $426 million was issued at a weighted dividend rate of 5.7 percent.
The operating companies continued to reduce financing costs by retiring
higher-cost bonds and preferred stock. Retirements, including maturities, of
bonds totaled $2.5 billion during 1993, $2.8 billion during 1992, and $1.0
billion during 1991. Retirements of preferred stock totaled $516 million
during 1993, $326 million during 1992, and $125 million during 1991. As a
result, the composite interest rate on long-term debt decreased from 9.2
percent at December 31, 1990, to 7.6 percent at December 31, 1993. During this
same period, the composite dividend rate on preferred stock declined from 8.5
percent to 6.4 percent.
In 1993, The Southern Company raised $205 million from the issuance of new
common stock under the Dividend Reinvestment and Stock Purchase Plan (DRIP) and
the Employee Savings Plan. At the close of 1993, the company's common stock
had a market value of $22.00 per share, compared with a book value of $11.96
per share. The market-to-book value ratio was 184 percent at the end of 1993,
compared with 168 percent at year-end 1992 and 156 percent at year-end 1991.
CAPITAL REQUIREMENTS FOR CONSTRUCTION
The construction program of the operating companies is budgeted at $1.5 billion
for 1994, $1.3 billion for 1995, and $1.5 billion for 1996. The total is $4.3
billion for the three years. Actual construction costs may vary from this
estimate because of factors such as changes in environmental regulations;
changes in existing nuclear plants to meet new regulations; revised load
projections; the cost and efficiency of construction labor, equipment, and
materials; and the cost of capital.
The operating companies do not have any baseload generating plants under
construction, and current energy demand forecasts do not require any additional
baseload facilities until well into the future. However, within the
7
<PAGE> 8
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
The Southern Company and Subsidiary Companies 1993 Annual Report
service area, the construction of combustion turbine peaking units of
approximately 1,700 megawatts of capacity is planned to be completed by 1996 to
meet increased peak-hour demands. In addition, significant construction of
transmission and distribution facilities and upgrading of generating plants
will be continuing.
OTHER CAPITAL REQUIREMENTS
In addition to the funds needed for the construction program, approximately
$789 million will be required by the end of 1996 for present sinking fund
requirements, redemptions announced, and maturities of long-term debt. Also,
the operating subsidiaries plan to continue a program to retire higher-cost
debt and preferred stock and replace these obligations with lower-cost capital.
ENVIRONMENTAL MATTERS
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 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, additional construction expenditures are estimated
to total approximately $275 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 construction expenditures
ranging from approximately $450 million to $800 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 average increase of up to 3 percent in 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
8
<PAGE> 9
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
The Southern Company and Subsidiary Companies 1993 Annual Report
requirements, on some Georgia Power 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 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. The impact of
any new standard will depend on the level chosen for the standard and cannot be
determined at this time.
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 standard will depend on the level chosen for the standard 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 non-hazardous status of coal
ash. However, the EPA has until 1998 to classify co-managed utility wastes --
coal ash and other utility wastes -- as either non-hazardous 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 Southern Company must comply with other environmental laws and
regulations that cover the handling and disposal of hazardous waste. Under
these various laws and regulations, the company could incur costs to clean up
properties currently or previously owned. The company conducts studies to
determine the extent of any required clean-up costs and has recognized in the
financial statements costs to clean up known sites.
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 Southern 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 Southern 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.
SOURCES OF CAPITAL
In early 1994, The Southern Company sold -- through a public offering -- common
stock with proceeds totaling $120 million. The company may require additional
equity capital during the remainder of 1994. The amount and timing of
additional equity capital to be raised in 1994 -- as well as in subsequent
years -- will be contingent on The Southern Company's investment opportunities.
Equity capital can be provided from any combination of public offerings,
private placements, or the company's stock plans. Any portion of the common
stock required during 1994 for the DRIP and the employee stock plans that is
not provided from the issuance of new stock will be acquired on the open market
in accordance with the terms of such plans.
The operating subsidiaries plan to obtain the funds required for
construction and other purposes from sources similar to those used in the past.
However, the type and timing of any financings -- if needed -- will depend on
market conditions and regulatory approval.
9
<PAGE> 10
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
The Southern Company and Subsidiary Companies 1993 Annual Report
Completing the sale of Unit 4 of Plant Scherer will provide some $260
million of cash during the years 1994 and 1995.
As required by the Nuclear Regulatory Commission, Alabama Power and Georgia
Power established external sinking funds for nuclear decommissioning costs.
For 1994 through 2000, the combined amount to be funded for both Alabama Power
and Georgia Power totals $36 million annually. The cumulative effect of
funding over this period will diminish internally funded capital and may
require capital from other sources. For additional information concerning
nuclear decommissioning costs, see Note 1 to the financial statements under
"Depreciation and Nuclear Decommissioning."
To meet short-term cash needs and contingencies, the system companies had
approximately $178 million of cash and cash equivalents and $1.1 billion of
unused credit arrangements with banks at the beginning of 1994.
To issue additional first mortgage bonds and preferred stock, the operating
companies must comply with certain earnings coverage requirements designated in
their mortgage indentures and corporate charters. The ability to issue
securities in the future will depend on coverages at that time. The coverage
ratios were, at the end of the respective years, as follows:
<TABLE>
<CAPTION>
Mortgage Charter
Coverage Coverage
(2.00* (1.50
Required) Required)
1993 1992 1993 1992
<S> <C> <C> <C> <C>
Alabama Power 5.70 5.86 2.71 2.56
Georgia Power 7.75 6.38 2.61 2.23
Gulf Power 5.79 5.27 2.56 2.35
Mississippi Power 5.78 5.68 2.67 2.51
Savannah Electric 3.94 5.01 2.20 2.65
</TABLE>
*Savannah Electric's requirement is 2.50.
10
<PAGE> 11
CONSOLIDATED STATEMENTS OF INCOME
For the Years Ended December 31, 1993, 1992, and 1991
The Southern Company and Subsidiary Companies 1993 Annual Report
<TABLE>
<CAPTION>
1993 1992 1991
(in millions)
<S> <C> <C> <C>
OPERATING REVENUES $8,489 $8,073 $8,050
OPERATING EXPENSES:
Operation --
Fuel 2,265 2,114 2,237
Purchased power 336 454 468
Proceeds from settlement of disputed contracts (Note 8) (3) (7) (181)
Other 1,448 1,317 1,321
Maintenance 653 613 637
Depreciation and amortization 793 768 763
Amortization of deferred Plant Vogtle expenses, net (Note 1) 36 (31) 16
Taxes other than income taxes 462 436 432
Federal and state income taxes 734 647 618
Total operating expenses 6,724 6,311 6,311
OPERATING INCOME 1,765 1,762 1,739
OTHER INCOME (EXPENSE):
Allowance for equity funds used during construction 9 10 13
Deferred return on Plant Vogtle (Note 1) -- -- 35
Interest income 30 32 30
Other, net (41) (50) (57)
Income taxes applicable to other income 57 39 21
INCOME BEFORE INTEREST CHARGES 1,820 1,793 1,781
INTEREST CHARGES AND PREFERRED DIVIDENDS:
Interest on long-term debt 595 684 757
Allowance for debt funds used during construction (13) (12) (18)
Interest on notes payable 30 16 20
Amortization of debt discount, premium, and expense, net 26 14 9
Other interest charges 87 34 29
Preferred dividends of subsidiary companies 93 104 108
Net interest charges and preferred dividends 818 840 905
CONSOLIDATED NET INCOME $1,002 $ 953 $ 876
COMMON STOCK DATA: (Note 10)
Average number of shares of common stock outstanding (in millions) 637 632 632
Earnings per share of common stock $1.57 $1.51 $ 1.39
Cash dividends paid per share of common stock $1.14 $1.10 $ 1.07
</TABLE>
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
For the Years Ended December 31, 1993, 1992, and 1991
<TABLE>
<CAPTION>
1993 1992 1991
(in millions)
<S> <C> <C> <C>
BALANCE AT BEGINNING OF YEAR $2,721 $2,490 $2,296
Consolidated net income 1,002 953 876
3,723 3,443 3,172
Cash dividends on common stock 726 695 676
Capital and preferred stock transactions, net 29 27 6
BALANCE AT END OF YEAR (Note 14) $2,968 $2,721 $2,490
</TABLE>
The accompanying notes are an integral part of these statements.
11
<PAGE> 12
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 1993, 1992, and 1991
The Southern Company and Subsidiary Companies 1993 Annual Report
<TABLE>
<CAPTION>
1993 1992 1991
(in millions)
<S> <C> <C> <C>
OPERATING ACTIVITIES:
Consolidated net income $ 1,002 $ 953 $ 876
Adjustments to reconcile consolidated net income
to net cash provided by operating activities --
Depreciation and amortization 1,011 969 968
Deferred income taxes and investment tax credits 189 215 15
Allowance for equity funds used during construction (9) (10) (13)
Deferred Plant Vogtle costs (Note 1) 36 (31) (19)
Non-cash proceeds from settlement of disputed
contracts (Note 8) -- (7) (141)
Gain on asset sales (36) -- (37)
Other, net (9) (25) 82
Changes in certain current assets and liabilities --
Receivables, net (55) (10) 68
Fossil fuel stock 138 53 21
Materials and supplies (2) (76) (1)
Accounts payable 43 35 (13)
Other (61) (71) 61
Net cash provided from operating activities 2,247 1,995 1,867
INVESTING ACTIVITIES:
Gross property additions (1,441) (1,105) (1,123)
Foreign utility operations (465) -- --
Sales of property 262 44 291
Other (37) 61 (45)
Net cash used for investing activities (1,681) (1,000) (877)
FINANCING ACTIVITIES:
Proceeds --
Common stock 205 30 --
Preferred stock 426 410 100
First mortgage bonds 2,185 1,815 380
Other long-term debt 592 256 140
Prepaid capacity revenues -- -- 53
Retirements --
Preferred stock (516) (326) (125)
First mortgage bonds (2,178) (2,575) (881)
Other long-term debt (450) (296) (200)
Increase in notes payable, net 114 525 180
Payment of common stock dividends (726) (695) (676)
Miscellaneous (137) (148) (41)
Net cash used for financing activities (485) (1,004) (1,070)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS 81 (9) (80)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR 97 106 186
CASH AND CASH EQUIVALENTS AT END OF YEAR $ 178 $ 97 $ 106
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid during the year for --
Interest (net of amount capitalized) $ 673 $ 743 $ 802
Income taxes 530 458 428
</TABLE>
The accompanying notes are an integral part of these statements.
12
<PAGE> 13
CONSOLIDATED STATEMENTS OF BALANCE SHEETS
At December 31, 1993, and 1992
The Southern Company and Subsidiary Companies 1993 Annual Report
<TABLE>
<CAPTION>
ASSETS 1993 1992
(in millions)
<S> <C> <C>
UTILITY PLANT:
Plant in service (Note 1) $27,687 $27,033
Less accumulated provision for depreciation 8,934 8,280
18,753 18,753
Nuclear fuel, at amortized cost 229 257
Construction work in progress (Note 4) 1,031 665
Total 20,013 19,675
Less property-related accumulated deferred income taxes (Note 9) -- 3,186
Total 20,013 16,489
OTHER PROPERTY AND INVESTMENTS:
Foreign utility operations, being amortized (Note 5) 559 --
Nuclear decommissioning trusts 88 52
Miscellaneous 89 75
Total 736 127
CURRENT ASSETS:
Cash and cash equivalents 178 97
Investment securities -- 199
Receivables, less accumulated provisions for uncollectible accounts
of $9 million in 1993 and $7 million in 1992 1,147 919
Fossil fuel stock, at average cost 254 392
Materials and supplies, at average cost 535 533
Prepayments 148 220
Vacation pay deferred (Note 1) 73 70
Total 2,335 2,430
DEFERRED CHARGES:
Deferred charges related to income taxes (Note 9) 1,546 --
Deferred Plant Vogtle costs (Note 1) 507 383
Debt expense, being amortized 33 28
Premium on reacquired debt, being amortized 288 222
Deferred fuel charges (Note 5) 70 89
Miscellaneous 383 270
Total 2,827 992
TOTAL ASSETS $25,911 $20,038
</TABLE>
The accompanying notes are an integral part of these balance sheets.
13
<PAGE> 14
CONSOLIDATED BALANCE SHEETS (continued)
At December 31, 1993 and 1992
The Southern Company and Subsidiary Companies 1993 Annual Report
<TABLE>
<CAPTION>
CAPITALIZATION AND LIABILITIES 1993 1992
(in millions)
<S> <C> <C>
CAPITALIZATION (See accompanying statements):
Common stock equity $7,684 $ 7,234
Preferred stock 1,332 1,351
Preferred stock subject to mandatory redemption 1 8
Long-term debt 7,412 7,241
Total 16,429 15,834
CURRENT LIABILITIES:
Preferred stock due within one year 1 65
Long-term debt due within one year 156 188
Notes payable 941 827
Accounts payable 698 646
Customer deposits 103 99
Taxes accrued --
Federal and state income 34 27
Other 172 145
Interest accrued 186 191
Vacation pay accrued 90 86
Miscellaneous 190 242
Total 2,571 2,516
DEFERRED CREDITS AND OTHER LIABILITIES:
Accumulated deferred income taxes (Note 9) 3,979 --
Deferred credits related to income taxes (Note 9) 1,051 --
Accumulated deferred investment tax credits 900 957
Disallowed Plant Vogtle capacity buyback costs 63 72
Prepaid capacity revenues 144 148
Miscellaneous 774 511
Total 6,911 1,688
COMMITMENTS AND CONTINGENT MATTERS (Notes 1, 3, 4, 5, 6, 7, 8, and 13)
TOTAL CAPITALIZATION AND LIABILITIES $25,911 $20,038
</TABLE>
The accompanying notes are an integral part of these balance sheets.
14
<PAGE> 15
CONSOLIDATED STATEMENTS OF CAPITALIZATION
At December 31, 1993 and 1992
The Southern Company and Subsidiary Companies 1993 Annual Report
<TABLE>
<CAPTION>
1993 1992 1993 1992
(in millions) (percent of total)
<S> <C> <C> <C> <C>
COMMON STOCK EQUITY:
Common stock, par value $5 per share --
Authorized -- 1 billion shares
Outstanding -- 1993: 637 million shares, 1992:
632 million shares (Note 10) $ 3,213 $ 1,582
Paid-in capital 1,502 2,929
Premium on preferred stock 1 2
Retained earnings (Note 14) 2,968 2,721
Total common stock equity 7,684 7,234 46.8% 45.7%
CUMULATIVE PREFERRED STOCK OF SUBSIDIARIES:
$100 par or stated value --
4.20% to 5.96% 199 199
6.32% to 7.88% 205 182
8.04% to 8.80% -- 225
$25 par or stated value --
$1.90 to $2.125 295 295
6.40% to 9.50% 323 200
Auction rates -- at January 1, 1994;
2.72% to 2.92% 70 50
Adjustable rates -- at January 1, 1994;
4.80% to 7.57% 240 200
Total (annual dividend requirement -- $85 million) 1,332 1,351 8.1 8.5
CUMULATIVE PREFERRED STOCK OF SUBSIDIARIES
SUBJECT TO MANDATORY REDEMPTION:
$100 par value --
11.36% 2 3
$25 stated value --
$2.43 -- 45
$2.50 -- 25
Total 2 73
Less amount due within one year 1 65
Total excluding amount due within one year 1 8 0.0 0.1
</TABLE>
15
<PAGE> 16
CONSOLIDATED STATEMENTS OF CAPITALIZATION (continued)
At December 31, 1993 and 1992
The Southern Company and Subsidiary Companies 1993 Annual Report
<TABLE>
<CAPTION>
1993 1992 1993 1992
(in millions) (percent of total)
<S> <C> <C> <C> <C> <C>
LONG-TERM DEBT:
First mortgage bonds of subsidiaries --
Maturity Interest Rates
1994 4 5/8% 26 78
1995 4 3/4% to 5 1/8% 141 211
1996 4 1/2% to 6 1/4% 235 100
1997 5 7/8% to 7 1/8% 25 113
1998 5% to 9.2% 249 98
1999 through 2003 6% to 8 3/4% 1,580 1,626
2004 through 2008 6 7/8% to 9% 230 182
2014 through 2018 9 3/8% to 10 3/4% 85 975
2019 through 2023 7.3% to 9 3/8% 1,909 1,040
2020 Variable rates -- 50
2032 Variable rates 200 200
Total first mortgage bonds 4,680 4,673
Other long-term debt (Note 11) 2,962 2,820
Unamortized debt premium (discount), net (74) (64)
Total long-term debt (annual interest
requirement -- $581 million) 7,568 7,429
Less amount due within one year (Note 12) 156 188
Long-term debt excluding amount due within one year 7,412 7,241 45.1 45.7
TOTAL CAPITALIZATION 16,429 $ 15,834 100.0% 100.0%
</TABLE>
<TABLE>
<CAPTION>
CONSOLIDATED STATEMENTS OF PAID-IN CAPITAL
For The Years Ended December 31, 1993, 1992, and 1991
1993 1992 1991
(in millions)
<S> <C> <C> <C>
BALANCE AT BEGINNING OF YEAR $2,929 $2,906 $2,906
Proceeds from sales of common stock over the par value -- 9.7 million
and 1.6 million shares in 1993 and 1992, respectively 179 23 --
Two-for-one stock split (Note 10) (1,606) -- --
BALANCE AT END OF YEAR $1,502 $2,929 $2,906
</TABLE>
The accompanying notes are an integral part of these statements.
16
<PAGE> 17
NOTES TO FINANCIAL STATEMENTS
The Southern Company and Subsidiary Companies 1993 Annual Report
1. SUMMARY OF SIGNIFICANT ACCOUNTING
POLICIES
GENERAL
The Southern Company is the parent company of five operating companies, a
system service company, Southern Electric International (Southern Electric),
Southern Nuclear Operating Company (Southern Nuclear), and various other
subsidiaries related to foreign utility operations and domestic non-utility
operations. At this time, the operations of the other subsidiaries are not
material. The operating companies provide electric service in four
Southeastern states. Contracts among the companies -- dealing with jointly
owned generating facilities, interconnecting transmission lines, and the
exchange of electric power -- are regulated by the Federal Energy Regulatory
Commission (FERC) or the Securities and Exchange Commission (SEC). The system
service company provides, at cost, specialized services to The Southern Company
and to 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 services to The
Southern Company's nuclear power plants.
The Southern Company is registered as a holding company under the Public
Utility Holding Company Act of 1935 (PUHCA). Both the company and its
subsidiaries are subject to the regulatory provisions of the PUHCA. The
operating companies also are subject to regulation by the FERC and their
respective state regulatory commissions. The companies follow generally
accepted accounting principles and comply with the accounting policies and
practices prescribed by their respective commissions.
All material intercompany items have been eliminated in consolidation.
Consolidated retained earnings at December 31, 1993, include $2.6 billion of
undistributed retained earnings of subsidiaries.
Certain prior years' data presented in the consolidated financial statements
have been reclassified to conform with current year presentation.
REVENUES AND FUEL COSTS
The operating companies accrue revenues for service rendered but unbilled at
the end of each fiscal period. Fuel costs are expensed as the fuel is used.
The operating companies' electric rates include provisions to adjust billings
for fluctuations in fuel and the energy component of purchased power costs.
Revenues are adjusted for differences between recoverable fuel costs and
amounts actually recovered in current rates.
Fuel expense includes the amortization of the cost of nuclear fuel and a
charge, based on nuclear generation, for the permanent disposal of spent
nuclear fuel. Total charges for nuclear fuel included in fuel expense amounted
to $137 million in 1993, $132 million in 1992, and $162 million in 1991.
Alabama Power and Georgia Power have contracts with the U.S. Department of
Energy (DOE) that provide for the permanent disposal of spent nuclear fuel,
which was scheduled to begin in 1998. However, the actual year this service
will begin is uncertain. Sufficient storage capacity currently is available to
permit operation into 2003 at Plant Hatch, into 2009 at Plant Vogtle, and into
2012 and 2014 at Plant Farley units 1 and 2, respectively.
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
assessment will be paid over a 15-year period, which began in 1993. This fund
will be used by the DOE for the decontamination and decommissioning of its
nuclear fuel enrichment facilities. The law provides that utilities will
recover these payments in the same manner as any other fuel expense. Georgia
Power -- based on its ownership interests -- and Alabama Power currently
estimate their liability under this law to be approximately $39 million and $46
million, respectively. These obligations are recorded in the Consolidated
Balance Sheets.
DEPRECIATION AND NUCLEAR DECOMMISSIONING
Depreciation of the original cost of depreciable utility plant in service is
provided primarily by using composite straight-line rates, which approximated
3.3 percent in 1993, 1992, and 1991. When property subject to depreciation is
retired or otherwise disposed of in the normal course of business, its cost --
together with the cost of removal, less salvage -- is charged to the
accumulated provision for depreciation. Minor items of property included in
the original cost of the plant are retired when the related property unit is
retired. Depreciation expense includes an amount for the expected costs of
decommissioning nuclear facilities.
17
<PAGE> 18
NOTES (continued)
The Southern Company and Subsidiary Companies 1993 Annual Report
In 1988, the Nuclear Regulatory Commission (NRC) adopted regulations
requiring all licensees operating commercial 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. Alabama Power and Georgia Power have established
external sinking funds to comply with the NRC's regulations. Prior to the
enactment of these regulations, Alabama Power and Georgia Power had 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. Alabama
Power and Georgia Power have filed plans with the NRC to ensure that -- over
time -- the deposits and earnings of the external trust funds will provide the
minimum funding amounts prescribed by the NRC.
The estimated cost of decommissioning and the amounts being recovered
through rates at December 31, 1993, for Alabama Power's Plant Farley and
Georgia Power's plants Hatch and Vogtle -- based on its ownership interests --
were as follows:
<TABLE>
<CAPTION>
Plant Plant Plant
Farley Hatch Vogtle
<S> <C> <C>
Site study basis (year) 1993 1990 1990
Estimated completion of
decommissioning (year) 2029 2027 2037
(in millions)
Cost of decommissioning:
Radiated structures $409 $184 $155
Non-radiated structures 75 35 62
Other 94 55 54
Total cost $578 $274 $271
(in millions)
Approved for ratemaking $578 $184 $155
Amount expensed in 1993 14 6 6
Balance in external trust fund 50 22 16
Balance in internal reserve 53 33 11
</TABLE>
The amounts in the internal reserve are being transferred into the external
trust fund over a set period of time as approved by the respective state public
service commissions.
The decommissioning cost estimates are based on prompt dismantlement and
removal of the plant from service. The actual decommissioning costs may vary
from the above estimates because of regulatory requirements, changes in
technology, and changes in costs of labor, materials, and equipment.
PLANT VOGTLE PHASE-IN PLANS
In 1987 and 1989, the Georgia Public Service Commission (GPSC) ordered that the
allowed costs of Plant Vogtle, a two-unit nuclear facility of which Georgia
Power owns 45.7 percent, be phased into rates under plans that meet the
requirements of Financial Accounting Standards Board (FASB) Statement No. 92,
Accounting for Phase-In Plans. Under these plans, Georgia Power deferred
financing costs and depreciation expense until the allowed investment was fully
reflected in rates as of October 1991. In 1991, the GPSC modified the Plant
Vogtle phase-in plan to begin earlier amortization of the costs deferred under
the plan. Also, the GPSC levelized capacity buyback expense from co-owners of
Plant Vogtle. See Note 3 for additional information regarding Georgia Power's
1991 rate order. Previously, pursuant to two separate interim accounting
orders by the GPSC, Georgia Power deferred substantially all operating expenses
and financing costs related to Plant Vogtle. Units 1 and 2 began commercial
operation in May 1987 and May 1989, respectively. The accounting orders were
for the periods from the date of each unit's commercial operation until October
1987 and 1989, respectively. Under phase-in plans and accounting orders from
the GPSC, Georgia Power deferred and began amortizing the costs -- recovered
through rates -- related to Plant Vogtle as follows:
<TABLE>
<CAPTION>
Unrecovered
Balance
Year-End
1993 1992 1991 1993
(in millions)
<S> <C> <C>
Deferred:
Financing costs $ -- $ -- $ 35 $388
Capacity buyback
expense 38 100 30 168
Other operating
expenses -- -- 7 279
Amortization of
amounts deferred (74) (69) (53) (328)
Net deferred amounts $ (36) $31 $ 19 $507
</TABLE>
The unrecovered balance above includes approximately $160 million related
to the adoption in 1993 of FASB Statement No. 109, Accounting for Income Taxes.
See Note 9 for information about Statement No. 109.
18
<PAGE> 19
NOTES (continued)
The Southern Company and Subsidiary Companies 1993 Annual Report
Each GPSC order calls for recovery of deferred costs within 10 years. Also,
the orders authorized Georgia Power to impute a return similar to allowance for
funds used during construction (AFUDC) on its investment in Plant Vogtle units
1 and 2 after the units began commercial operation. These deferred returns are
included in the above amounts, except for the equity component in the case of
the Unit 2 accounting order.
INCOME TAXES
The companies provide 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
Southern Company adopted FASB Statement No. 109, Accounting for Income Taxes.
Statement No. 109 required, among other things, conversion to the liability
method of accounting for accumulated deferred income taxes. See Note 9 for
additional information about Statement No. 109.
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. The composite rates used by the companies to calculate
AFUDC during the years 1991 through 1993 ranged from a before-income-tax rate
of 4.9 percent to 11.4 percent. Deferred income taxes related to capitalized
debt cost were $5 million, $4 million, and $7 million in 1993, 1992, and 1991,
respectively. After Plant Vogtle units 1 and 2 began commercial operation in
1987 and 1989, respectively, Georgia Power imputed a deferred return similar to
AFUDC on its investment in the units under the short-term cost deferrals and
phase-in plans, as discussed earlier. AFUDC and the deferred return, net of
income tax, as a percent of consolidated net income were 1.7 percent in 1993,
1.8 percent in 1992, and 6.0 percent in 1991. The deferred return was
discontinued in October 1991 after the allowed investment in Plant Vogtle was
fully reflected in rates.
UTILITY PLANT
Utility plant is stated at original cost less regulatory disallowances.
Original cost includes: materials; labor; minor items of property; appropriate
administrative and general costs; payroll-related costs such as taxes,
pensions, and other benefits; and the estimated cost of funds used during
construction. The cost of maintenance, repairs, and replacement of minor items
of property is charged to maintenance expense. The cost of replacements of
property (exclusive of minor items of property) is charged to utility plant.
CASH AND CASH EQUIVALENTS
For purposes of the Consolidated 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
In accordance with FASB Statement No. 107, Disclosure About Fair Value of
Financial Instruments, all financial instruments of The Southern 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 $ 88 $ 90
Long-term debt 7,321 7,729
Preferred stock subject
to mandatory redemption 2 2
1992
Carrying Fair
Amount Value
(in millions)
Nuclear decommissioning trusts $ 52 $ 53
Investment securities 199 221
Long-term debt 7,165 7,566
Preferred stock subject
to mandatory redemption 73 79
</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
19
<PAGE> 20
NOTES (continued)
The Southern Company and Subsidiary Companies 1993 Annual Report
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 1992, Georgia Power converted to the inventory
method of accounting for certain emergency spare parts. This conversion
resulted in a regulatory liability that will be amortized as a credit to income
over approximately four years. This conversion will not have a material effect
on net income.
VACATION PAY
The operating companies' employees earn their 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 companies accrue a current liability for earned
vacation pay and record a current asset representing the future recoverability
of this cost. The amount was $73 million and $70 million at December 31, 1993
and 1992, respectively. In 1994, an estimated 71 percent of the 1993 deferred
vacation cost will be expensed, and the balance will be charged to construction
and other accounts.
2. RETIREMENT BENEFITS
PENSION PLAN
The system companies have defined benefit, trusteed, non-contributory pension
plans that cover 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.
Primarily, the companies use 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 system companies also provide certain medical care and life insurance
benefits for retired employees. Substantially all employees may become
eligible for these benefits when they retire. A qualified trust for medical
benefits 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 system companies 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 Georgia Power to phase in the adoption of Statement No.
106 to cost of service over a five-year period, whereby one-fifth of the
additional costs would be expensed in 1993 and the remaining costs would be
deferred. An additional one-fifth of the costs would be expensed each
succeeding year until the costs are fully reflected in cost of service in 1997.
The costs deferred during the five-year period will be amortized to expense
over a 15-year period beginning in 1998. As a result of regulatory treatment
allowed by the operating companies' respective public service commissions, the
adoption of Statement No. 106 did not have a material impact on consolidated
net income.
Prior to 1993, the system companies, except for Georgia Power and Savannah
Electric, recognized these benefit costs on an accrual basis using the
"aggregate cost" actuarial method, which spreads the expected cost of such
benefits over the remaining periods of employees' service as a level percentage
of payroll costs. Consistent with regulatory treatment in these years, Georgia
Power and Savannah Electric recognized these costs on a cash basis as payments
were made. The total costs of such benefits recognized by system companies in
1992 and 1991 were $42 million and $36 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 FASB Statement Nos. 87 and 106, respectively. Retiree medical
and life insurance information is shown only for 1993 because Statement
20
<PAGE> 21
NOTES (continued)
The Southern Company and Subsidiary Companies 1993 Annual Report
No. 106 was adopted as 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 obligation:
Vested benefits $ 1,534 $ 1,293
Non-vested benefits 76 62
Accumulated benefit obligation 1,610 1,355
Additional amounts related to
projected salary increases 558 638
Projected benefit obligation 2,168 1,993
Less:
Fair value of plan assets 3,337 2,994
Unrecognized net gain (1,060) (891)
Unrecognized prior service cost 72 77
Unrecognized transition asset (152) (164)
Prepaid asset recognized in the
Consolidated Balance Sheets $ 29 $ 23
</TABLE>
<TABLE>
<CAPTION>
Postretirement
Medical Life
1993 1993
(in millions)
<S> <C> <C>
Actuarial present value of
benefit obligation:
Retirees and dependents $ 243 $ 75
Employees eligible to retire 48 --
Other employees 389 96
Accumulated benefit obligation 680 171
Less:
Fair value of plan assets 95 2
Unrecognized net loss (gain) 76 (13)
Unrecognized transition obligation 419 113
Accrued liability recognized in the
Consolidated Balance Sheets $ 90 $ 69
</TABLE>
The weighted average rates assumed in the above
actuarial calculations were:
<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 percent would increase the accumulated
medical benefit obligation at December 31, 1993, by $129 million and the
aggregate of the service and interest cost components of the net retiree
medical cost by $14 million.
Components of the plans' net cost are shown below:
<TABLE>
<CAPTION>
Pension
1993 1992 1991
(in millions)
<S> <C> <C> <C>
Benefits earned during the year $ 76 $ 75 $ 71
Interest cost on projected
benefit obligation 156 146 138
Actual return on plan assets (432) (135) (745)
Net amortization and deferral 186 (85) 551
Net pension cost (income) $ (14) $ 1 $ 15
</TABLE>
Of the above net pension amounts, pension income of $9 million in 1993 and
pension expense of $2 million in 1992 and $11 million in 1991 were recorded in
operating expenses, and the remainder was recorded in construction and other
accounts.
<TABLE>
<CAPTION>
Postretirement
Medical Life
1993 1993
(in millions)
<S> <C> <C>
Benefits earned during the year $ 21 $ 6
Interest cost on accumulated
benefit obligation 43 13
Amortization of transition
obligation over 20 years 22 6
Actual return on plan assets (12) --
Net amortization and deferral 5 --
Net postretirement cost $ 79 $ 25
</TABLE>
Of the above net postretirement medical and life insurance costs recorded in
1993, $64 million was charged to operating expenses, $21 million was deferred,
and the remainder was charged to construction and other accounts.
21
<PAGE> 22
NOTES (continued)
The Southern Company and Subsidiary Companies 1993 Annual Report
WORK FORCE REDUCTION PROGRAMS
The system companies have incurred additional costs for work force reduction
programs. The costs related to these programs were $35 million, $37 million,
and $72 million for the years 1993, 1992, and 1991, respectively. A portion of
the cost of these programs was deferred and is being amortized in accordance
with regulatory treatment. The unamortized balance of these costs was $19
million at December 31, 1993.
3. LITIGATION AND REGULATORY MATTERS
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, and this matter is concluded.
STOCKHOLDER SUIT
In April 1991, two Southern Company stockholders filed a derivative action suit
in the U.S. District Court for the Southern District of Georgia against certain
current and former directors and officers of The Southern Company. The suit
alleges violations of the Federal Racketeer Influenced and Corrupt
Organizations Act (RICO) by officers and breaches of fiduciary duty and gross
negligence by all defendants resulting from alleged fraudulent accounting for
spare parts, illegal political campaign contributions, violations of federal
securities laws involving misrepresentations and omissions in SEC filings, and
concealment of the foregoing acts. The complaint seeks damages -- including
treble damages pursuant to RICO -- in an unspecified amount, which if awarded,
would be payable to The Southern Company. The plaintiffs' amended complaint
was dismissed by the court in March 1992. The court ruled the plaintiffs had
failed to present adequately their allegation that The Southern Company board
of directors' refusal of an earlier demand by the plaintiffs was wrongful. The
plaintiffs have appealed the dismissal to the U.S. Court of Appeals for the
11th Circuit.
ALABAMA POWER HEAT PUMP FINANCING SUIT
In September 1990, two customers of Alabama Power filed a civil complaint in
the Circuit Court of Shelby County, Alabama, against Alabama Power seeking to
represent all persons who, prior to June 23, 1989, entered into agreements with
Alabama Power for the financing of heat pumps and other merchandise purchased
from vendors other than Alabama Power. The plaintiffs contended that Alabama
Power was required to obtain a license under the Alabama Consumer Finance Act
to engage in the business of making consumer loans. The plaintiffs were
seeking an order declaring these agreements null and void and requiring Alabama
Power to refund all payments -- principal and interest -- made under these
agreements. The aggregate amount under these agreements, together with interest
paid, currently is estimated to be $40 million.
In June 1993, the court ordered Alabama Power to refund or forfeit interest
of approximately $10 million because of Alabama Power's failure to obtain such
license. However, the court's order did not require any refund or forfeiture
with respect to any principal payments under the agreements at issue. Alabama
Power has appealed the court's order to the Supreme Court of Alabama.
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.
GULF POWER COAL BARGE TRANSPORTATION SUIT
In 1993, a complaint against Gulf Power and the system service company was
filed in federal district court in Ohio by two companies with which Gulf Power
had contracted for the transportation by barge for certain Gulf Power coal
supplies. The complaint alleges breach of the contract by Gulf Power and seeks
damages estimated by the plaintiffs to be in excess of $85 million.
22
<PAGE> 23
NOTES (continued)
The Southern Company and Subsidiary Companies 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.
ALABAMA POWER RATE ADJUSTMENT PROCEDURES
In November 1982, the Alabama Public Service Commission (APSC) adopted rates
that provide for periodic adjustments based upon Alabama Power's earned return
on end-of-period retail common equity. The rates also provide for adjustments
to recognize the placing of new generating facilities in retail service. Both
increases and decreases have been placed into effect since the adoption of
these rates. The rate adjustment procedures allow a return on common equity
range of 13.0 percent to 14.5 percent and limit increases or decreases in rates
to 4 percent in any calendar year.
The APSC issued an order in December 1991 that reduced a scheduled 2.03
percent annual increase in rates to 1.03 percent, effective January 1992. The
1 percent reduction will remain in effect through 1994. The rate reduction was
designed to refund to retail ratepayers a portion of the benefits from a
settled contract dispute with Gulf States Utilities Company (Gulf States). The
present value of this portion of the settlement -- amounting to some $60
million -- is being amortized to income to offset the rate reduction in
accordance with the APSC's rate order. See Note 8 for additional information
concerning the Gulf States settlement.
Also in the December 1991 rate order, the APSC reaffirmed its satisfaction
with the ratemaking mechanism and stated that it did not foresee any further
review or changes in the procedures until after 1994. The ratemaking
procedures will remain in effect after 1994 unless the APSC votes to modify or
discontinue them.
GEORGIA POWER'S 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 Georgia Power'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. Georgia Power 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 Georgia Power's request
for an accounting order allowing Georgia Power to defer all current unrecovered
and future costs related to these programs until the superior court's decision
is reversed or until the next general rate case proceedings. An association of
industrial customers has filed a petition for review of the accounting order in
superior court. Georgia Power'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 the company's financial statements.
GEORGIA POWER 1991 RATE ORDER; PHASE-IN PLAN MODIFICATIONS
Georgia Power received a rate order in 1991 from the GPSC that modified the
Plant Vogtle phase-in plans to begin earlier amortization of the costs deferred
under the plans. The amortization period began October 1991 -- rather than
October 1994 as originally scheduled -- and extends through September 1999. In
addition, the GPSC ordered the levelization of capacity buyback expense from
the co-owners of Plant Vogtle over a six-year period beginning October 1991.
This results in net cost deferrals during the first three years and subsequent
amortization of the deferred amounts in the last three years.
MISSISSIPPI POWER RETAIL RATE ADJUSTMENT PLAN
Mississippi Power's retail base rates have been set under a Performance
Evaluation Plan (PEP) since 1986 with various modifications in 1991 and the
latest in 1994. In 1993, the Mississippi Public Service Commission (MPSC)
ordered Mississippi Power to review and propose changes that would enhance the
plan. Mississippi Power filed a revised plan, and the MPSC approved PEP-2 on
January 4, 1994. Under PEP-2, Mississippi Power's rate of return will be
measured on retail net investment rather than on common equity, as previously
calculated. Also, the number of indicators used to evaluate Mississippi
Power's performance was reduced to three with emphasis on price and service to
the customer. In addition, PEP-2 provides for the sharing of rate adjustments
based on low rates and on the performance rating. The evaluation periods for
PEP-2 are semiannual. Any change in rates is limited to 2 percent of retail
revenues per period before a public hearing is required. PEP-2 will remain in
effect until the MPSC modifies or terminates the plan.
23
<PAGE> 24
NOTES (continued)
The Southern Company and Subsidiary Companies 1993 Annual Report
FERC REVIEWS 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.
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.
4. CONSTRUCTION PROGRAM
GENERAL
The operating companies are engaged in continuous construction programs,
currently estimated to total some $1.5 billion in 1994, $1.3 billion in 1995,
and $1.5 billion in 1996. These estimates include AFUDC of $34 million in
1994, $41 million in 1995, and $35 million in 1996. The construction programs
are subject to periodic review and revision, and actual construction costs may
vary from the above estimates because of numerous factors. These factors
include changes in business conditions; revised load growth estimates; changes
in environmental regulations; changes in existing nuclear plants to meet new
regulatory requirements; increasing costs of labor, equipment, and materials;
and cost of capital. At December 31, 1993, significant purchase commitments
were outstanding in connection with the construction program. The operating
companies do not have any new baseload generating plants under construction.
However, within the service area, the construction of combustion turbine
peaking units of approximately 1,700 megawatts is planned to be completed by
1996. In addition, significant construction will continue related to
transmission and distribution facilities and the upgrading and extension of the
useful lives of generating plants.
See Management's Discussion and Analysis under "Environmental Matters" for
information on the impact of the Clean Air Act Amendments of 1990 and other
environmental matters.
ROCKY MOUNTAIN PROJECT STATUS
In its 1985 financing order, the GPSC concluded that completion of the Rocky
Mountain pumped storage hydroelectric project in 1991 was not economically
justifiable and reasonable and withheld authorization for Georgia Power to
spend funds from approved securities issuances on that project. In 1988,
Georgia Power 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 6. However, full recovery of
Georgia Power's costs depends on the GPSC's treatment of the project's cost and
disposition of the project's capacity output. In the event Georgia Power
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. At December 31, 1993, Georgia Power'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, Georgia Power'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. Georgia Power 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.
5. FINANCING, INVESTMENT, AND
COMMITMENTS
GENERAL
In early 1994, The Southern Company sold -- through a public offering -- 5.6
million shares of common stock with proceeds totaling $120 million. The
company may require additional equity capital during the remainder of 1994.
The amount and timing of additional equity capital to be raised in 1994 -- as
well as in subsequent years -- will be contingent on The Southern Company's
investment opportunities. Equity capital can be provided from any combination
of public offerings, private placements, or the company's stock plans.
24
<PAGE> 25
NOTES (continued)
The Southern Company and Subsidiary Companies 1993 Annual Report
To the extent possible, the operating companies' construction programs are
expected to be financed primarily from internal sources. Short-term debt will
be utilized when necessary; the amounts available are discussed below. The
subsidiary companies may issue additional long-term debt and preferred stock
primarily for the purposes of debt maturities and for redeeming higher-cost
securities.
FOREIGN UTILITY OPERATIONS
During 1993, The Southern Company made investments of approximately $315
million in utilities that own and operate generating facilities in various
foreign markets. The consolidated financial statements reflect these
investments in majority-owned subsidiaries on a consolidated basis and other
investments on an equity basis.
BANK CREDIT ARRANGEMENTS
At the beginning of 1994, unused credit arrangements with banks totaled $1.1
billion, of which approximately $500 million expires at various times during
1994 and 1995; $130 million expires at May 1, 1996; $400 million expires at
June 30, 1996; and $70 million expires at December 1, 1996.
Georgia Power's revolving credit agreements of $150 million, of which $130
million remained unused as of December 31, 1993, expire May 1, 1996. During
the term of these agreements, Georgia Power may convert short-term borrowings
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 Georgia Power's option. In
connection with these credit arrangements, Georgia Power agrees to pay
commitment fees based on the unused portions of the commitments or to maintain
compensating balances with the banks.
The $400 million expiring June 30, 1996, is under revolving credit
arrangements with several banks providing The Southern Company, Alabama Power,
and Georgia Power up to the total credit amount of $400 million. To provide
liquidity support to commercial paper programs, $135 million and $165 million
of the $400 million available credit are currently dedicated to the exclusive
use of Alabama Power and Georgia Power, respectively. During the term of these
agreements, 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.
Mississippi Power has $70 million of revolving credit agreements expiring
December 1, 1996. These agreements allow short-term borrowings to 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 Mississippi Power's option. In
connection with these credit arrangements, Mississippi Power agrees to pay
commitment fees based on the unused portions of the commitments or to maintain
compensating balances with the banks.
Savannah Electric has $20 million of revolving credit arrangements expiring
December 31, 1995. These agreements allow short-term borrowings to 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 Savannah Electric's
option. In connection with these credit arrangements, Savannah Electric agrees
to pay commitment fees based on the unused portions of the commitments.
In connection with all other lines of credit, the companies have the option
of paying fees or maintaining compensating balances, which are substantially
all the cash of the companies except for daily working funds and similar items.
These balances are not legally restricted from withdrawal.
In addition, the companies from time to time borrow under uncommitted lines
of credit with banks, and in the case of Alabama Power and Georgia Power,
through commercial paper programs that have the liquidity support of committed
bank credit arrangements.
ASSETS SUBJECT TO LIEN
The operating companies' mortgages, which secure the first mortgage bonds
issued by the companies, constitute a direct first lien on substantially all of
the companies' respective fixed property and franchises.
FUEL COMMITMENTS
To supply a portion of the fuel requirements of the system's generating plants,
the subsidiary companies have
25
<PAGE> 26
NOTES (continued)
The Southern Company and Subsidiary Companies 1993 Annual Report
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 $15 billion at December 31,
1993. Additional commitments for coal and nuclear fuel will be required in the
future to supply the operating companies' fuel needs.
To take advantage of lower-cost coal supplies, agreements were reached in
1986 for the payment of $121 million to terminate two contracts for the supply
of coal to Plant Daniel, which is jointly owned by Gulf Power and Mississippi
Power. Also, in March 1988, Gulf Power made an advance payment of $60 million
to a coal supplier under an agreement to lower the cost of future coal
purchased under an existing contract. These amounts are being amortized to
expense. The remaining unamortized amount included in deferred charges at
December 31, 1993, was $70 million.
OPERATING LEASES
The operating companies have entered into coal rail car rental agreements with
various terms and expiration dates. Rental expense totaled $11 million, $9
million, and $7 million for 1993, 1992, and 1991, respectively. At December
31, 1993, estimated minimum rental commitments for noncancelable operating
leases were as follows:
<TABLE>
<CAPTION>
Amounts
(in millions)
<S> <C>
1994 $ 12
1995 14
1996 12
1997 12
1998 12
1999 and thereafter 226
Total minimum payments $ 288
</TABLE>
6. FACILITY SALES AND JOINT OWNERSHIP
AGREEMENTS
In 1992, Alabama Power sold an undivided interest in units 1 and 2 of Plant
Miller and related facilities to Alabama Electric Cooperative, Inc.
Since 1975, Georgia Power has sold undivided interests in plants Vogtle,
Hatch, Scherer, and Wansley in varying amounts, together with transmission
facilities, to OPC, the Municipal Electric Authority of Georgia (MEAG), and the
city of Dalton, Georgia. Georgia Power has completed two of four separate
transactions to sell Unit 4 of Plant Scherer to two Florida utilities. See
Note 7 for additional information concerning these sales. In addition, Georgia
Power has entered into a joint ownership agreement with OPC with respect to the
Rocky Mountain project, as discussed later.
At December 31, 1993, Alabama Power's and Georgia Power's ownership and
investment (exclusive of nuclear fuel) in jointly owned facilities with the
above entities were as follows:
<TABLE>
<CAPTION>
Jointly Owned Facilities
Percent Amount of Accumulated
Ownership Investment Depreciation
(in millions)
<S> <C> <C> <C>
Plant Vogtle
(nuclear) 45.7% $3,285 $540
Plant Hatch
(nuclear) 50.1 840 325
Plant Miller
(coal)
Units 1 and 2 91.8 703 247
Plant Scherer
(coal)
Units 1 and 2 8.4 111 33
Unit 4 33.1 236 31
Plant Wansley
(coal) 53.5 286 125
Rocky Mountain
(pumped storage) 25.0* 197 --
</TABLE>
*Estimated ownership at date of completion.
Georgia Power and OPC have entered into a joint ownership agreement
regarding the 848-megawatt Rocky Mountain pumped storage hydroelectric project.
Under the agreement, Georgia Power will retain its present investment in the
project and OPC will finance, complete, and operate the facility. Upon
completion, Georgia Power will own an undivided interest in the project equal
to the proportion its investment bears to the total investment in the project
(excluding each party's cost of funds and ad valorem taxes). Based on current
cost estimates, Georgia Power's final ownership is estimated at approximately
25 percent of the project at completion. Georgia Power has held preliminary
discussions with other parties regarding the potential disposition of its
remaining interest in the project.
26
<PAGE> 27
NOTES (continued)
THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES 1993 ANNUAL REPORT
Alabama Power and Georgia Power have contracted to operate and maintain
the jointly owned facilities -- except for the Rocky Mountain project -- as
agents for their respective co-owners. The companies' proportionate share of
their plant operating expenses is included in the corresponding operating
expenses in the Consolidated Statements of Income.
In connection with a joint ownership arrangement at Plant Vogtle, Georgia
Power has remaining commitments to purchase declining fractions of OPC's and
MEAG's capacity and energy from this plant for periods of up to 10 years
following commercial operation (and, with regard to a portion of the 5 percent
additional 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 such capacity are
required whether any capacity is available. The energy cost of these purchases
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 in the
Consolidated Statements of Income. Capacity payments totaled $183 million,
$289 million, and $320 million, for 1993, 1992, and 1991, respectively.
Projected 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. Also, a portion of the above capacity payments
relates to Plant Vogtle costs that were written off after being disallowed for
retail ratemaking purposes.
In 1991, the GPSC ordered that the Plant Vogtle capacity buyback expense be
levelized over a six-year period. The amounts deferred and not expensed in the
year paid totaled $38 million in 1993, $100 million in 1992, and $30 million in
1991. The projected net amount to be deferred in 1994 is $1 million. The
projected net amortization of the deferred expense is $49 million in 1995, $62
million in 1996, and $57 million in 1997.
7. PLANNED SALES OF INTEREST IN PLANT
SCHERER
Georgia Power has completed two of four separate transactions to sell Unit 4 of
Plant Scherer to Florida Power & Light Company (FP&L) and Jacksonville Electric
Authority (JEA) for a total price of approximately $806 million, including any
gains on these transactions. FP&L would eventually own approximately 76.4
percent of the unit, with JEA owning the remainder. The capacity from this
unit was previously dedicated to long-term power sales contracts with Gulf
States that were suspended in 1988. Georgia Power will continue to operate the
unit.
The completed and scheduled remaining transactions are as follows:
<TABLE>
<CAPTION>
Closing Percent
Date Capacity Ownership Amount
(megawatts) (in millions)
<S> <C> <C> <C>
July 1991 290 35.46% $291
June 1993 258 31.44 253
June 1994 135 16.55 132
June 1995 135 16.55 130
Total 818 100.00% $806
</TABLE>
Plant Scherer -- a jointly owned coal-fired generating plant -- has four
units with a total capacity of 3,272 megawatts. Unit 4 was completed in 1989.
See Note 6 for information regarding current plant ownership.
8. LONG-TERM POWER SALES
AGREEMENTS
GENERAL
The operating subsidiaries 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 area. Certain of
these agreements are non-firm and are based on capacity of the system in
general. Other agreements are firm and pertain to capacity related to specific
generating units. Because the energy is generally sold at cost under these
agreements, revenues from capacity sales primarily affect profitability. The
capacity revenues have been as follows:
<TABLE>
<CAPTION>
Unit Other
Year Power Long-Term Total
(in millions)
<S> <C> <C> <C>
1993 $312 $38 $350
1992 435 22 457
1991 468 22 490
</TABLE>
Long-term non-firm power of 400 megawatts was sold in 1993 to Florida Power
Corporation (FPC). In January 1994, this amount decreased to 200 megawatts,
and the contract will expire at year-end.
Unit power from specific generating plants is currently being sold to FP&L,
FPC, JEA, and the city of Tallahassee, Florida. Under these agreements, an
average
27
<PAGE> 28
NOTES (continued)
The Southern Company and Subsidiary Companies 1993 Annual Report
of 1,700 megawatts of capacity is scheduled to be sold during 1994 and 1995.
Thereafter, these sales will decline to some 1,600 megawatts and remain at that
approximate level -- unless reduced by FP&L, FPC, and JEA for the periods after
1999 -- until the expiration of the contracts in 2010.
GULF STATES SETTLEMENT COMPLETED
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 other 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 -- less the amounts
to be refunded to customers and the amounts previously included in income --
The Southern Company recorded an increase in consolidated net income of $114
million, or 18 cents per share, in November 1991. With respect to Alabama
Power's portion of proceeds received in 1991, see Note 3 concerning the
regulatory treatment of amounts being refunded to retail customers over a
three-year period.
9. INCOME TAXES
Effective January 1, 1993, The Southern 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 consolidated net income.
The adoption also resulted in the recording of additional deferred income taxes
and related assets and liabilities. The related assets of $1.5 billion are
revenues to be received from customers. These assets are attributable to tax
benefits flowed through to customers in prior years and to taxes applicable to
capitalized AFUDC. The related liabilities of $1.1 billion 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
(in millions)
<S> <C> <C> <C>
Total provision for income taxes:
Federal --
Currently payable $424 $343 $506
Deferred -- current year 224 225 139
-- reversal of
prior years (51) (41) (121)
Deferred investment tax
credits (20) (6) (11)
577 521 513
State --
Currently payable 64 50 76
Deferred -- current year 39 46 23
-- reversal of
prior years (3) (9) (15)
100 87 84
Total 677 608 597
Less income taxes charged
(credited) to other income (57) (39) (21)
Federal and state income
taxes charged to operations $734 $647 $618
</TABLE>
The tax effects of temporary differences between the carrying amounts of
assets and liabilities in the financial statements and their respective tax
bases, which give rise to deferred tax assets and liabilities, are as follows:
<TABLE>
<CAPTION>
1993
(in millions)
<S> <C>
Deferred tax liabilities:
Accelerated depreciation $2,496
Property basis differences 1,741
Deferred plant costs 161
Other 289
Total 4,687
Deferred tax assets:
Federal effect of state deferred taxes 102
Other property basis differences 292
Deferred costs 69
Pension and other benefits 46
Other 210
Total 719
Net deferred tax liabilities 3,968
Portion included in current assets, net 11
Accumulated deferred income taxes
in the Consolidated Balance Sheets $3,979
</TABLE>
28
<PAGE> 29
NOTES (continued)
The Southern Company and Subsidiary Companies 1993 Annual Report
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 Consolidated Statements of Income. Credits amortized in
this manner amounted to $29 million in 1993, $41 million in 1992, and $48
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 income tax rate to the effective
income tax rate is as follows:
<TABLE>
<CAPTION>
1993 1992 1991
<S> <C> <C> <C>
Federal statutory rate 35.0% 34.0% 34.0%
State income tax,
net of federal deduction 3.7 3.4 3.5
Non-deductible book
depreciation 1.9 2.2 2.9
Difference in prior years'
deferred and current tax rate (1.3) (1.5) (1.5)
Other (1.1) (1.6) (1.1)
Effective income tax rate 38.2% 36.5% 37.8%
</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.
10. COMMON STOCK
STOCK DISTRIBUTION
In January 1994, The Southern Company board of directors authorized a
two-for-one common stock split in the form of a stock distribution for each
share held as of February 7, 1994. For all reported common stock data, the
number of common shares outstanding and per share amounts for earnings,
dividends, and market price have been adjusted to reflect the stock
distribution.
SHARES RESERVED
At December 31, 1993, a total of 24 million shares was reserved for issuance
pursuant to the Dividend Reinvestment and Stock Purchase Plan, the Employee
Savings Plan, and the Executive Stock Option Plan.
EXECUTIVE STOCK OPTION PLAN
The Southern Company's Executive Stock Option Plan authorizes the granting of
non-qualified stock options to key employees of The Southern Company, including
officers. Currently, 34 employees are eligible to participate in the plan. As
of December 31, 1993, 38 current and former employees participated in the plan.
The maximum number of shares of common stock that may be issued under the
Executive Stock Option Plan may not exceed 6 million. The price of options
granted to date has been at the fair market value of the shares on the date of
grant. Options granted to date become exercisable pro rata over a maximum
period of four years from date of grant, such that all options generally are
exercisable by 1997. Options outstanding will expire upon termination of the
plan, which will occur on December 7, 1997, unless terminated earlier by the
board of directors. Stock option activity in 1992 and 1993 is summarized
below:
<TABLE>
<CAPTION>
Shares Average
Subject Option Price
To Option Per Share
<S> <C> <C>
Balance at December 31, 1991 1,399,088 $13.02
Options granted 434,840 18.09
Options canceled -- --
Options exercised (644,806) 12.75
Balance at December 31, 1992 1,189,122 15.02
Options granted 359,492 21.22
Options canceled -- --
Options exercised (183,804) 14.14
Balance at December 31, 1993 1,364,810 $16.77
Shares reserved for future grants:
At December 31, 1991 4,508,776
At December 31, 1992 4,073,936
At December 31, 1993 3,714,444
Options exercisable:
At December 31, 1992 243,566
At December 31, 1993 475,795
</TABLE>
29
<PAGE> 30
NOTES (continued)
The Southern Company and Subsidiary Companies 1993 Annual Report
11. OTHER LONG-TERM DEBT
Details of other long-term debt are as follows:
<TABLE>
<CAPTION>
December 31,
1993 1992
(in millions)
<S> <C> <C>
Obligations incurred in connection
with the sale by public authorities
of tax-exempt pollution control
revenue bonds:
Collateralized --
5.375% to 10.0% due 2003-2023 $ 708 $ 512
Variable rates (3.05% to 3.40%)
due 2016-2022 63 23
Non-collateralized --
5.9% to 7.25% due 2003-2006 6 32
7.2% to 9.2% due 2007-2010 -- 92
Variable rate (3.7% at 1/1/94)
due 2011 10 10
7.2% to 12.25% due 2013-2014 644 738
6.75% to 10.6% due 2015-2017 890 891
5.8% due 2022 10 --
Variable rate (3.55% at 1/1/94)
due 2019 59 59
Variable rates (3.7% to 6.2% at
1/1/94) due 2021 and 2022 23 23
Less funds on deposit with trustees -- 2
2,413 2,378
Capitalized lease obligations:
Nuclear fuel 96 104
Buildings 146 154
Other 5 6
247 264
Notes payable:
8.25% due 1993-1995 35 51
7.5% due 1993-1995 2 3
9.75% due 1993-2010 10 10
8.0% due 1993 -- 2
4.36% to 8.00% due 1993-1995 101 20
4.62% to 9.4% due 1996-2000 94 25
Adjustable rates (3.45% to
4.41% at 1/1/94) due 1994 60 67
302 178
Total $2,962 $2,820
</TABLE>
With respect to the collateralized pollution control revenue bonds, the
operating companies have authenticated and delivered to trustees a like
principal amount of first mortgage bonds as security for obligations under
installment sale or loan agreements. The principal and interest on the first
mortgage bonds will be payable only in the event of default under the
agreements.
Assets acquired under capital leases are recorded as utility plant in
service, and the related obligation is classified as other long-term debt. The
net book value of capitalized leases was $217 million and $236 million at
December 31, 1993 and 1992, respectively. At December 31, 1993, the composite
interest rates for nuclear fuel, buildings, and other were 3.6 percent, 9.7
percent, and 12.0 percent, respectively. Sinking fund requirements and/or
serial maturities through 1998 applicable to other long-term debt are as
follows: $89 million in 1994; $154 million in 1995; $58 million in 1996; $26
million in 1997; and $7 million in 1998.
12. LONG-TERM DEBT DUE WITHIN ONE YEAR
A summary of the improvement fund requirements and scheduled maturities and
redemptions of long-term debt due within one year is as follows:
<TABLE>
<CAPTION>
1993 1992
(in millions)
<S> <C> <C>
Bond improvement fund requirements $ 51 $ 54
Less:
Portion to be satisfied by certifying
property additions 3 2
Reacquired bonds 25 --
Cash sinking fund requirements 23 52
First mortgage bond maturities
and redemptions 44 57
Other long-term debt maturities
(Note 11) 89 79
Total $156 $188
</TABLE>
The first mortgage bond improvement (sinking) fund requirements amount to 1
percent of each outstanding series of bonds authenticated under the indentures
prior to January 1 of each year, other than those issued to collateralize
pollution control and other obligations. The requirements may be satisfied by
depositing cash or reacquiring bonds, or by pledging additional property equal
to 166 2/3 percent of such requirements.
30
<PAGE> 31
NOTES (continued)
The Southern Company and Subsidiary Companies 1993 Annual Report
13. NUCLEAR INSURANCE
Under the Price-Anderson Amendments Act of 1988, Alabama Power and Georgia
Power maintain agreements of indemnity with the NRC that, together with private
insurance, cover third-party liability arising from any nuclear incident
occurring at the companies' 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, excluding any applicable state
premium taxes, for Alabama Power and Georgia Power -- based on its ownership
and buyback interests -- is $159 million and $171 million, respectively, per
incident but not more than an aggregate of $20 million and $22 million,
respectively, to be paid for each incident in any one year.
Alabama Power and Georgia Power are members 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. Alabama Power's and Georgia Power's maximum annual
assessments are limited to $14 million and $18 million, respectively, under
current policies.
Additionally, both companies have 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 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 annual assessments under current policies for Alabama
Power and Georgia Power for excess property damage would be $16 million and $15
million, respectively. The replacement power assessments are $9 million for
Alabama Power and $13 million for Georgia 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.
Alabama Power and Georgia Power participate 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, Alabama Power and Georgia
Power could be subject to a maximum total assessment of $6 million and $7
million, respectively.
31
<PAGE> 32
NOTES (continued)
The Southern Company and Subsidiary Companies 1993 Annual Report
14. COMMON STOCK DIVIDEND
RESTRICTIONS
The income of The Southern Company is derived primarily from equity in earnings
of its operating subsidiaries. At December 31, 1993, $1.6 billion of
consolidated retained earnings was restricted against the payment by the
operating companies of cash dividends on common stock under terms of bond
indentures or charters.
15. QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
Summarized quarterly financial data for 1993 and 1992 are as follows:
<TABLE>
<CAPTION>
Per Common Share*
Operating Operating Consolidated Price Range
Quarter Ended Revenues Income Net Income Earnings Dividends High Low
(in millions)
<S> <C> <C> <C> <C> <C> <C> <C>
March 1993 $1,840 $377 $177 $0.28 $0.285 21 3/8 18 3/8
June 1993 2,068 426 250 0.39 0.285 22 1/2 19 3/8
September 1993 2,636 637 442 0.70 0.285 23 20 1/2
December 1993 1,945 324 133 0.20 0.285 23 5/8 20 3/4
March 1992 $1,808 $387 $185 $0.29 $0.275 17 3/8 15 1/8
June 1992 2,011 428 223 0.36 0.275 17 5/8 15 5/8
September 1992 2,386 609 404 0.64 0.275 19 17 3/8
December 1992 1,868 338 141 0.22 0.275 19 1/2 17 5/8
</TABLE>
*Common stock data have been adjusted to reflect a two-for-one stock split in
the form of a stock distribution for each share held as of February 7, 1994.
The company's business is influenced by seasonal weather conditions and the
timing of rate changes.
32
<PAGE> 33
SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA
The Southern Company and Subsidiary Companies 1993 Annual Report
(See Note Below)
<TABLE>
<CAPTION>
1993 1992 1991
<S> <C> <C> <C>
OPERATING REVENUES (in millions) $ 8,489 $ 8,073 $ 8,050
CONSOLIDATED NET INCOME (in millions) $ 1,002 $ 953 $ 876
EARNINGS PER SHARE OF COMMON STOCK $ 1.57 $ 1.51 $ 1.39
CASH DIVIDENDS PAID PER SHARE OF COMMON STOCK $ 1.14 $ 1.10 $ 1.07
RETURN ON AVERAGE COMMON EQUITY (percent) 13.43 13.42 12.74
TOTAL ASSETS (in millions) $ 25,911 $ 20,038 $ 19,863
GROSS PROPERTY ADDITIONS (in millions) $ 1,441 $ 1,105 $ 1,123
CAPITALIZATION (in millions):
Common stock equity $ 7,684 $ 7,234 $ 6,976
Preferred stock 1,332 1,351 1,207
Preferred and preference stock subject
to mandatory redemption 1 8 126
Long-term debt 7,412 7,241 7,992
Total excluding amounts due within one year $ 16,429 $ 15,834 $ 16,301
CAPITALIZATION RATIOS (percent):
Common stock equity 46.8 45.7 42.8
Preferred stock 8.1 8.6 8.2
Long-term debt 45.1 45.7 49.0
Total excluding amounts due within one year 100.0 100.0 100.0
OTHER COMMON STOCK DATA:
Book value per share (year-end) $ 11.96 $ 11.43 $ 11.05
Market price per share:
High 23 5/8 19 1/2 17 3/8
Low 18 3/8 15 1/8 12 7/8
Close 22 19 1/4 17 1/8
Market-to-book ratio (year-end) (percent) 183.9 168.4 155.5
Price-earnings ratio (year-end) (times) 14.0 12.7 12.4
Dividends paid (in millions) $ 726 $ 695 $ 676
Dividend yield (year-end) (percent) 5.2 5.7 6.2
Dividend payout ratio (percent) 72.4 72.9 77.1
Cash coverage of dividends (year-end) (times) 2.9 2.8 2.5
Proceeds from sales of stock (in millions) $ 204 $ 30 --
Shares outstanding (in thousands):
Average 637,319 631,844 631,307
Year-end 642,662 632,917 631,307
Stockholders of record (year-end) 237,105 247,378 254,568
FIRST MORTGAGE BONDS (in millions):
Issued $ 2,185 $ 1,815 $ 380
Retired 2,178 2,575 881
PREFERRED STOCK (in millions):
Issued $ 426 $ 410 $ 100
Retired 516 326 125
CUSTOMERS (year-end) (in thousands):
Residential 2,996 2,950 2,903
Commercial 427 414 403
Industrial 18 18 18
Other 4 4 4
Total 3,445 3,386 3,328
EMPLOYEES (year-end) 28,743 29,085 30,402
</TABLE>
Note: Common stock data have been adjusted to reflect a two-for-one stock split
in the form of a stock distribution for each share held as of February 7, 1994.
33
<PAGE> 34
SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA
The Southern Company and Subsidiary Companies 1993 Annual Report
(See Note Below)
<TABLE>
<CAPTION>
1990 1989 1988 1987 1986 1985 1984 1983
<S> <C> <C> <C> <C> <C> <C> <C>
$ 8,053 $ 7,620 $ 7,287 $ 7,204 $ 7,033 $ 6,999 $ 6,350 $ 5,673
$ 604 $ 846 $ 846 $ 577 $ 903 $ 845 $ 735 $ 604
$ 0.96 $ 1.34 $ 1.36 $ 0.96 $ 1.56 $ 1.56 $ 1.47 $ 1.32
$ 1.07 $ 1.07 $ 1.07 $ 1.07 $ 1.0325 $ 0.975 $ 0.915 $ 0.8625
8.85 12.49 13.03 9.27 15.61 16.59 16.55 15.67
$ 19,955 $ 20,092 $ 19,731 $ 19,518 $ 18,483 $ 16,855 $ 15,327 $ 13,790
$ 1,185 $ 1,346 $ 1,754 $ 1,853 $ 2,367 $ 2,242 $ 2,130 $ 1,722
$ 6,783 $ 6,861 $ 6,686 $ 6,307 $ 6,133 $ 5,443 $ 4,741 $ 4,135
1,207 1,209 1,259 1,139 1,214 1,114 1,004 954
151 191 206 224 178 194 206 214
8,458 8,575 8,433 8,333 7,812 7,220 6,774 6,439
$ 16,599 $ 16,836 $ 16,584 $ 16,003 $ 15,337 $ 13,971 $ 12,725 $ 11,742
40.9 40.8 40.3 39.4 40.0 38.9 37.3 35.2
8.2 8.3 8.8 8.5 9.1 9.4 9.5 9.9
50.9 50.9 50.9 52.1 50.9 51.7 53.2 54.9
100.0 100.0 100.0 100.0 100.0 100.0 100.0 100.0
$ 10.74 $ 10.87 $ 10.60 $ 10.28 $ 10.35 $ 9.72 $ 9.08 $ 8.60
14 5/8 14 7/8 12 1/8 14 1/2 13 5/8 11 5/8 9 3/8 8 7/8
11 1/2 11 10 1/8 8 7/8 10 1/8 8 7/8 7 1/8 7 1/4
13 7/8 14 1/2 11 1/8 11 1/8 12 5/8 11 1/8 9 3/8 8 1/8
129.7 134.0 105.5 108.8 122.5 114.5 103.9 95.2
14.6 10.9 8.2 11.7 8.2 7.1 6.4 6.2
$ 676 $ 675 $ 661 $ 628 $ 583 $ 512 $ 444 $ 380
7.7 7.3 9.6 9.6 8.4 9.2 10.2 11.0
111.8 79.8 78.1 108.9 64.6 60.6 60.4 63.0
2.8 2.6 2.3 2.0 2.7 2.6 3.1 3.4
-- $ 4 $ 194 $ 247 $ 379 $ 373 $ 318 $ 333
631,307 631,303 622,292 601,390 580,252 541,244 501,313 456,262
631,307 631,307 630,898 613,565 592,364 560,063 522,018 480,649
263,046 273,751 290,725 296,079 297,302 318,221 336,165 351,012
$ 300 $ 280 $ 335 $ 700 $ 735 $ 20 $ 150 $ 129
146 201 273 369 875 69 71 53
$ -- $ -- $ 120 $ 125 $ 100 $ 150 $ 50 $ 50
96 21 10 160 53 6 6 11
2,865 2,824 2,781 2,733 2,675 2,611 2,541 2,473
396 392 384 374 362 348 336 324
18 18 18 18 17 17 17 17
4 4 4 4 4 4 4 4
3,283 3,238 3,187 3,129 3,058 2,980 2,898 2,818
30,263 30,530 32,523 32,612 32,358 32,354 31,753 31,499
</TABLE>
34
<PAGE> 35
SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA (continued)
The Southern Company and Subsidiary Companies 1993 Annual Report
<TABLE>
<CAPTION>
1993 1992 1991
<S> <C> <C> <C>
OPERATING REVENUES (in millions):
Residential $ 2,696 $ 2,402 $ 2,391
Commercial 2,313 2,181 2,122
Industrial 2,200 2,126 2,088
Other 68 64 65
Total retail 7,277 6,773 6,666
Sales for resale within service area 447 409 417
Sales for resale outside service area 613 797 884
Total revenues from sales of electricity 8,337 7,979 7,967
Other revenues 152 94 83
Total $ 8,489 $ 8,073 $ 8,050
KILOWATT-HOUR SALES (in millions):
Residential 36,807 33,627 33,622
Commercial 32,847 31,025 30,379
Industrial 48,738 47,816 46,050
Other 814 777 817
Total retail 119,206 113,245 110,868
Sales for resale within service area 13,258 12,107 12,320
Sales for resale outside service area 12,445 16,632 19,839
Total 144,909 141,984 143,027
AVERAGE REVENUE PER KILOWATT-HOUR (cents):
Residential 7.32 7.14 7.11
Commercial 7.04 7.03 6.99
Industrial 4.51 4.45 4.53
Total retail 6.10 5.98 6.01
Sales for resale 4.12 4.20 4.05
Total sales 5.75 5.62 5.57
AVERAGE ANNUAL KILOWATT-HOUR USE PER RESIDENTIAL CUSTOMER 12,378 11,490 11,659
AVERAGE ANNUAL REVENUE PER RESIDENTIAL CUSTOMER $ 906.60 $ 820.67 $ 829.18
PLANT NAMEPLATE CAPACITY RATINGS (year-end) (megawatts) 29,513 29,830 29,915
MAXIMUM PEAK-HOUR DEMAND (megawatts):
Winter 19,432 19,121 19,166
Summer 25,937 24,146 25,261
SYSTEM RESERVE MARGIN (at peak) (percent) 13.2 14.3 16.5
ANNUAL LOAD FACTOR (percent) 59.4 60.3 58.3
PLANT AVAILABILITY (percent):
Fossil-steam 87.9 88.6 91.3
Nuclear 85.9 85.2 83.4
SOURCE OF ENERGY SUPPLY (percent):
Coal 72.2 71.7 72.6
Nuclear 16.1 16.2 16.2
Hydro 3.9 4.6 4.4
Oil and gas 0.7 0.5 0.6
Purchased power 7.1 7.0 6.2
Total 100.0 100.0 100.0
TOTAL FUEL ECONOMY DATA:
BTU per net kilowatt-hour generated 9,994 9,976 10,022
Cost of fuel per million BTU (cents) 166.85 162.58 168.28
Average cost of fuel per net kilowatt-hour generated (cents) 1.67 1.62 1.69
</TABLE>
35
<PAGE> 36
SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA (continued)
The Southern Company and Subsidiary Companies 1993 Annual Report
<TABLE>
<CAPTION>
1990 1989 1988 1987 1986 1985 1984 1983
<S> <C> <C> <C> <C> <C> <C> <C>
$ 2,342 $ 2,194 $ 2,103 $ 2,042 $ 1,996 $ 1,825 $ 1,751 $ 1,641
2,062 1,965 1,835 1,692 1,613 1,512 1,410 1,284
2,085 2,011 1,945 1,870 1,845 1,830 1,790 1,600
64 60 56 54 52 50 47 42
6,553 6,230 5,939 5,658 5,506 5,217 4,998 4,567
412 401 480 461 511 436 456 439
977 928 777 1,028 957 1,289 854 619
7,942 7,559 7,196 7,147 6,974 6,942 6,308 5,625
111 61 91 57 59 57 42 48
$ 8,053 $ 7,620 $ 7,287 $ 7,204 $ 7,033 $ 6,999 $ 6,350 $ 5,673
33,118 31,627 31,041 30,583 29,501 27,088 26,163 25,425
29,658 28,454 27,005 25,593 24,166 22,512 20,816 19,512
45,974 45,022 43,675 42,113 40,503 39,804 39,055 35,618
806 787 763 737 723 713 663 645
109,556 105,890 102,484 99,026 94,893 90,117 86,697 81,200
11,134 11,419 14,806 13,282 14,347 11,079 11,193 10,829
24,402 24,228 15,860 22,905 16,909 27,881 21,374 15,509
145,092 141,537 133,150 135,213 126,149 129,077 119,264 107,538
7.07 6.94 6.77 6.68 6.77 6.74 6.69 6.45
6.96 6.91 6.79 6.61 6.67 6.71 6.77 6.58
4.53 4.47 4.45 4.44 4.56 4.60 4.58 4.49
5.98 5.88 5.80 5.71 5.80 5.79 5.76 5.62
3.91 3.73 4.10 4.11 4.69 4.43 4.02 4.02
5.47 5.34 5.40 5.29 5.53 5.38 5.29 5.23
11,637 11,287 11,255 11,307 11,157 10,515 10,434 10,395
$ 822.93 $ 782.90 $ 762.42 $ 754.96 $ 754.93 $ 708.46 $ 698.26 $ 670.76
29,532 29,532 27,552 27,610 26,262 26,262 25,397 25,377
17,629 20,772 18,685 18,185 19,665 19,347 16,353 15,502
25,981 24,399 23,641 23,194 23,255 21,778 20,210 20,999
14.0 21.0 15.0 16.2 11.4 17.6 32.8 27.0
56.6 58.6 59.8 58.7 57.2 57.4 58.9 53.9
91.9 92.2 91.3 91.2 90.3 90.5 90.5 90.5
83.0 87.0 78.4 84.5 74.2 80.3 66.9 75.8
72.1 71.5 77.7 77.8 79.4 78.5 77.3 75.2
15.6 15.7 14.5 13.1 11.5 12.0 11.8 13.2
4.4 5.2 2.3 3.3 2.2 3.1 5.6 6.4
1.3 1.1 0.7 0.6 0.9 0.3 0.2 0.5
6.6 6.5 4.8 5.2 6.0 6.1 5.1 4.7
100.0 100.0 100.0 100.0 100.0 100.0 100.0 100.0
10,065 10,086 10,094 10,122 10,171 10,193 10,208 10,357
172.81 171.00 170.36 176.64 185.89 191.24 191.44 184.25
1.74 1.72 1.72 1.78 1.89 1.95 1.95 1.91
</TABLE>
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