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 12, 1997
------------------------------
GEORGIA POWER COMPANY
- ------------------------------------------------------------------------------
(Exact name of registrant as specified in its charter)
Georgia 1-6468 58-0257110
- ------------------------------------------------------------------------------
(State or other jurisdiction (Commission (IRS Employer
of incorporation) File Number) Identification No.)
333 Piedmont Avenue, N.E. Atlanta, Georgia 30308
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(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code (404) 526-6526
--------------------------
N/A
- ------------------------------------------------------------------------------
(Former name or former address, if changed since last report.)
<PAGE>
Item 7. Financial Statements and Exhibits.
(c) Exhibits.
23 - Consent of Arthur Andersen LLP.
27 - Financial Data Schedule.
99 - Audited Financial Statements of Georgia
Power Company as of December 31, 1996.
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934,
the registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
GEORGIA POWER COMPANY
By /s/ Wayne Boston
Wayne Boston
Assistant Secretary
Date: March 3, 1997
Exhibit 23
ARTHUR ANDERSEN LLP
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the incorporation
of our report dated February 12, 1997 on the financial statements of Georgia
Power Company, included in this Form 8-K, into Georgia Power Company's
previously filed Registration Statement File Nos. 33-49661 and 33-60345.
/s/ Arthur Andersen LLP
Atlanta, Georgia
February 27, 1997
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<LEGEND>
This schedule contains summary financial information extracted from the
financial statements filed as Exhibit 99 and is qualified in its entirity by
reference to such financial statements.
</LEGEND>
<CIK> 0000041091
<NAME> GEORGIA POWER COMPANY
<MULTIPLIER> 1,000
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<FISCAL-YEAR-END> DEC-31-1996
<PERIOD-END> DEC-31-1996
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 10,353,916
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325,000
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<LONG-TERM-DEBT-NET> 3,173,927
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</TABLE>
MANAGEMENT'S REPORT
Georgia Power Company 1996 Annual Report
The management of Georgia Power Company has prepared this annual report and is
responsible for the financial statements and related information. These
statements were prepared in accordance with generally accepted accounting
principles appropriate in the circumstances, and necessarily include amounts
that are based on the best estimates and judgments of management. Financial
information throughout this annual report is consistent with the financial
statements.
The Company maintains a system of internal accounting controls to provide
reasonable assurance that assets are safeguarded and that the books and records
reflect only authorized transactions of the Company. Limitations exist in any
system of internal controls based upon the recognition that the cost of the
system should not exceed its benefits. The Company believes that its system of
internal accounting controls maintains an appropriate cost/benefit relationship.
The Company's system of internal accounting controls is evaluated on an
ongoing basis by the Company's internal audit staff. The Company's independent
public accountants also consider certain elements of the internal control system
in order to determine their auditing procedures for the purpose of expressing an
opinion on the financial statements.
The audit committee of the board of directors, which is composed of six
directors who are not employees, provides a broad overview of management's
financial reporting and control functions. At least three times a year this
committee meets with management, the internal auditors, and the independent
public accountants to ensure that these groups are fulfilling their obligations
and to discuss auditing, internal control and financial reporting matters. The
internal auditors and the independent public accountants have access to the
members of the audit committee at any time.
Management believes that its policies and procedures provide reasonable
assurance that the Company's operations are conducted with a high standard of
business ethics.
In management's opinion, the financial statements present fairly, in all
material respects, the financial position, results of operations and cash flows
of Georgia Power Company in conformity with generally accepted accounting
principles.
/s/ H. Allen Franklin
H. Allen Franklin
President and Chief
Executive Officer
/s/ Warren Y. Jobe
Warren Y. Jobe
Executive Vice President,
Treasurer and Chief
Financial Officer
February 12, 1997
1
<PAGE>
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors of Georgia Power Company:
We have audited the accompanying balance sheets and statements of capitalization
of Georgia Power Company (a Georgia corporation and a wholly owned subsidiary of
Southern Company) as of December 31, 1996 and 1995, and the related statements
of income, retained earnings, paid-in capital, and cash flows for each of the
three years in the period ended December 31, 1996. These financial statements
are the responsibility of the Company's management. Our responsibility is to
express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements (pages 10-31) referred to above
present fairly, in all material respects, the financial position of Georgia
Power Company as of December 31, 1996 and 1995, and the results of its
operations and its cash flows for each of the three years in the period ended
December 31, 1996, in conformity with generally accepted accounting principles.
/s/ Arthur Andersen LLP
Atlanta, Georgia
February 12, 1997
2
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL
CONDITION
Georgia Power Company 1996 Annual Report
RESULTS OF OPERATIONS
Earnings
Georgia Power Company's 1996 earnings totaled $580 million, representing a $29
million (4.7 percent) decrease from 1995. Earnings for 1995 included an
after-tax gain of approximately $12 million from the completion of the sale of
Plant Scherer Unit 4. The remaining decrease in 1996 earnings was primarily due
to increased operating and maintenance expenses, partially offset by lower
interest charges compared to the prior year. The Company's 1995 earnings
increased 15.9 percent over 1994. Earnings for 1994 were reduced by a $55
million after-tax charge related to work force reduction programs. Excluding the
charge related to 1994 work force reduction programs, earnings for 1995
increased 4.8 percent over 1994 primarily due to higher retail energy sales and
lower interest charges, partially offset by higher operating expenses.
Revenues
The following table summarizes the factors impacting operating revenues for the
1994-1996 period:
Increase (Decrease)
From Prior Year
-----------------------------------
1996 1995 1994
-----------------------------------
Retail - (in millions)
Sales growth $ 58 $110 $ 67
Weather (25) 69 (128)
Fuel cost recovery 28 66 (35)
Demand-side programs (10) 36 (12)
------------------------------------------------------------------
Total retail 51 281 (108)
- ------------------------------------------------------------------
Sales for resale -
Non-affiliates (9) (61) (183)
Affiliates (41) 16 (1)
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Total sales for resale (50) (45) (184)
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Other operating revenues 10 7 3
- ------------------------------------------------------------------
Total operating revenues $ 11 $243 ($289)
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Percent change 0.3% 5.8% (6.5)%
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Retail revenues of $4.0 billion in 1996 increased $51 million (1.3 percent)
over the prior year primarily due to strong economic growth and an increase in
sales to existing customers. Retail revenues increased in 1995 over the prior
year primarily due to the continued expansion of Georgia's economy and the hot
summer of 1995. Milder-than-normal weather occurred during the summer of 1994.
Fuel revenues generally represent the direct recovery of fuel expense,
including the fuel component of purchased energy, and do not affect net income.
Revenues from demand-side option programs generally represent the direct
recovery of program costs. See Note 3 to the financial statements under
"Demand-Side Conservation Programs" for further information on these programs.
Revenues from sales to non-affiliated utilities decreased in both 1996 and
1995. Revenues from sales to non-affiliated utilities outside the service area
under long-term contracts consist of capacity and energy components. Capacity
revenues reflect the recovery of fixed costs and a return on investment under
the contracts. Energy is generally sold at variable cost. The capacity and
energy components were as follows:
1996 1995 1994
-------------------------------
(in millions)
Capacity $41 $53 $ 84
Energy 43 45 82
- --------------------------------------------------------------
Total $84 $98 $166
==============================================================
Contractual unit power sales to Florida utilities for 1996 and 1995 are down
primarily due to scheduled reductions that corresponded with the sales to these
utilities of portions of Plant Scherer Unit 4 in June 1995 and June 1994. The
amount of capacity under these contracts declined by 75 megawatts and 155
megawatts in 1996 and 1995, respectively. In 1997, the contracted capacity will
decline another 14 megawatts.
Revenues from other sales to non-affiliated utilities outside the service
area in 1996 increased $14 million over the prior year due to a 74.5 percent
increase in sales. Revenues for 1995 decreased by $27 million due to a 51.9
percent decrease in sales. These sales are primarily energy sales generally sold
at variable cost.
Revenues from municipalities and cooperatives in Georgia decreased in 1996
primarily due to the recognition of an agreement to refund $14 million to these
customers and a decrease of approximately $8 million in capacity revenues under
3
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 1996 Annual Report
a power supply agreement with Oglethorpe Power Corporation (OPC). See Note 3 to
the financial statements under "Wholesale Litigation" for additional information
on the refund agreement. Beginning in September 1996, OPC decreased its
purchases of capacity by 250 megawatts and has notified the Company of its
intent to decrease purchases of capacity by an additional 250 megawatts in
September 1997, and an additional 250 megawatts in September 1998. This decrease
in revenues discussed above was partially offset by revenues from increased
sales compared to the prior year due to higher demand. Sales increased in 1995
primarily due to higher summer demand resulting from the hot weather.
Revenues from sales to affiliated companies within the Southern electric
system will vary from year to year depending on demand and the availability and
cost of generating resources at each company. Sales to affiliated companies do
not have a significant impact on earnings.
Kilowatt-hour (KWH) sales for 1996 and the percent change by year were as
follows:
Percent Change
----------------------------
1996
KWH 1996 1995 1994
--------- ------------------------------
(in billions)
Residential 17.8 3.0% 10.4% (5.8)%
Commercial 20.8 4.9 5.9 2.5
Industrial 26.2 3.6 3.9 3.0
Other 0.5 8.6 2.0 5.0
-------
Total retail 65.3 3.9 6.2 0.4
-------
Sales for resale -
Non-affiliates 7.9 19.4 (17.3) (44.3)
Affiliates 1.2 (56.9) (10.4) 0.9
-------
Total sales for resale 9.1 (3.0) (15.4) (36.4)
-------
Total sales 74.4 3.0 2.8 (8.0)
=======
Residential, commercial and industrial energy sales growth in 1996 reflected
strong economic growth and an increase in sales to existing customers. The 1995
sales growth was the result of favorable weather conditions in addition to
increased customers and economic growth.
Expenses
Fuel costs constitute the single largest expense for the Company. The mix of
fuel sources for generation of electricity is determined primarily by system
load, the unit cost of fuel consumed, and the availability of hydro and nuclear
generating units. The amount and sources of generation and the average cost of
fuel per net kilowatt-hour generated were as follows:
1996 1995 1994
--------------------------
Total generation
(billions of kilowatt-hours) 63.7 64.3 62.4
Sources of generation
(percent) --
Coal 74.3 73.7 74.8
Nuclear 22.4 22.6 21.9
Hydro 2.7 3.0 3.1
Oil and gas 0.6 0.7 0.2
Average cost of fuel per net
kilowatt-hour generated
(cents) --
Coal 1.55 1.67 1.67
Nuclear 0.55 0.60 0.63
Oil and gas * * *
Total 1.35 1.44 1.44
- --------------------------------------------------------------
* Not meaningful because of minimal generation from
fuel source.
Fuel expense decreased 7.3 percent in 1996 because of a decrease in
generation resulting from the timing of maintenance at nuclear plants and a
lower average cost of fuel. Fuel expense increased 3.5 percent in 1995 because
of higher generation which stemmed from greater demand.
Purchased power expense increased $72 million (22.8 percent) in 1996
primarily due to increased purchases from affiliated companies as a result of
the timing of maintenance at nuclear plants discussed above. The increase in
1996 was partially offset by a decrease in energy purchases from wholesale
customers within the service areas and a decline in contractual capacity
purchases from the co-owners of Plant Vogtle. Purchased power expense decreased
$36 million in 1995, reflecting the declining Plant Vogtle contractual capacity
purchases and decreased purchases from affiliated companies. The declines in
4
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 1996 Annual Report
Plant Vogtle contractual capacity purchases did not have a significant impact on
earnings in 1996 and 1995 since these costs are being levelized over six years
under the terms of the 1991 Georgia Public Service Commission (GPSC) retail rate
order. The levelization is reflected in the amortization of deferred Plant
Vogtle costs in the Statements of Income. See Note 1 to the financial statements
under "Plant Vogtle Phase-In Plans" for additional information.
The Company has incurred expenses for separation benefits associated with
its work force reduction programs. These expenses were $39 million in 1996, $11
million in 1995, and $82 million in 1994.
Other operation and maintenance (O&M) expenses, excluding the provision for
separation benefits, increased 2.9 percent in 1996 primarily as a result of
initiatives to reduce fossil generation materials inventory levels, an
adjustment to deferred postretirement benefits to reflect changes in the retiree
benefits plan, and increased costs under a three-year retail accounting order
effective January 1, 1996. See Note 3 to the financial statements under "Retail
Accounting Order" for additional information. Other O&M expenses increased 12.2
percent in 1995 primarily as a result of the recognition of costs associated
with demand-side option programs and increased maintenance expenses. The
demand-side option program costs were offset in part by increases in retail
revenues. During 1995, the Company expensed an additional $58 million of
demand-side option program and other related costs, as compared to 1994, of
which approximately $29 million was not collected through rate riders. See Note
3 to the financial statements under "Demand-Side Conservation Programs" for
additional information on the recovery of these program costs.
Depreciation and amortization increased $11 million in 1996 primarily due to
accelerated depreciation of generating plant pursuant to the retail accounting
order effective January 1996 discussed above, and an increase in
plant-in-service. Depreciation and amortization increased $43 million in 1995
primarily due to additional plant investment, accelerated amortization of
software costs, and an increase in nuclear decommissioning expenses.
Taxes other than income taxes increased 1.2 percent in 1996 and 5.2 percent
in 1995, primarily reflecting higher franchise taxes paid to municipalities as a
result of increased sales.
Other, net decreased $35 million in 1996 primarily due to expenses in
connection with activities related to the 1996 Summer Olympic games and the
completion of the sale, in June 1995, of Plant Scherer Unit 4, which resulted in
an after-tax gain of approximately $12 million. An increase in charitable
contributions resulted in the decrease in other income (expense), net in 1995.
Interest expense decreased $52 million (17.4 percent) and $51 million (14.6
percent) in 1996 and 1995, respectively. Dividends on preferred stock also
decreased $3 million in 1996. These reductions are primarily due to the
refinancing of securities. The Company refinanced or retired $510 million and
$1.0 billion of securities in 1996 and 1995, respectively. The retirements
included the redemption of $264 million of long-term debt with the proceeds from
the 1995 and 1994 Plant Scherer Unit 4 sales.
The Company has deferred certain expenses and recorded a deferred return
related to Plant Vogtle under phase-in plans. See Note 1 to the financial
statements under "Plant Vogtle Phase-In Plans" for information regarding the
deferral and subsequent amortization of costs related to Plant Vogtle.
Effects of Inflation
The Company is subject to rate regulation and income tax laws that are based on
the recovery of historical costs. Therefore, inflation creates an economic loss
because the Company is recovering its costs of investments in dollars that have
less purchasing power. While the inflation rate has been relatively low in
recent years, it continues to have an adverse effect on the Company because of
the large investment in long-lived utility plant. Conventional accounting for
historical cost does not recognize 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. The level of future earnings depends on numerous
factors including regulatory matters and energy sales.
5
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 1996 Annual Report
On January 1, 1996, the Company began operating under a three-year retail
accounting order. Under the order, which was approved by the GPSC on February
16, 1996, the Company's earnings are evaluated against a retail return on common
equity range of 10 percent to 12.5 percent. Earnings in excess of 12.5 percent
will be used to accelerate the amortization of regulatory assets or depreciation
of electric plant. At its option, the Company may also recognize accelerated
amortization or depreciation of assets within the allowed return on common
equity range. The Company is required to absorb cost increases of approximately
$29 million annually during the order's three-year operation, including $14
million annually of accelerated depreciation of electric plant. During the
order's operation, the Company will not file for a general base rate increase
unless its projected retail return on common equity falls below 10 percent.
Under the order, on July 1, 1998 the Company will make a general rate case
filing in response to which the GPSC would be expected either to continue
provisions of the accounting order or adopt different ones. The Company's 1996
retail return on common equity was within the 10 percent to 12.5 percent range.
In November 1996, on appeal by a consumer group, the Superior Court of Fulton
County (Georgia) reversed the GPSC's order and remanded the matter to the GPSC.
The court found that statutory requirements applicable to rate cases should have
been, but were not, followed. The Company and the GPSC have appealed the court's
decision. The Company is continuing to recognize expenses in accordance with the
accounting order while it is under appeal.
Growth in energy sales is subject to a number of factors which traditionally
have included changes in contracts with neighboring utilities, energy
conservation practiced by customers, the elasticity of demand, weather,
competition, initiatives to increase sales to existing customers, and the rate
of economic growth in the Company's service area. Assuming normal weather,
retail sales growth is projected to be approximately 2 percent annually on
average during 1997 through 1999.
The Company has entered into a four-year purchase power agreement to meet
peaking needs. Beginning in 1996, the Company purchased 400 megawatts of
capacity. In 1997, this amount will decline to 300 megawatts and in 1998 and
1999 to 200 megawatts. Capacity payments are projected to be $5 million in 1997
and $3 million in 1998 and 1999. The Company has also entered into a 30-year
purchase power agreement whereby the Company will buy electricity during peak
periods from a planned 300 megawatt cogeneration facility starting in June 1998.
Capacity and fixed O&M payments are projected to be $13 million in 1998 and $15
million in 1999.
The amortization of Plant Vogtle costs deferred under phase-in plans will
decline by $16 million in 1997, $89 million in 1998, $12 million in 1999, and
$19 million in 2000. These costs will be fully amortized by September 1999. See
Note 1 to the financial statements under "Plant Vogtle Phase-In Plans" for
additional information. Additionally, work force reduction programs implemented
in the past three years will assist in efforts to control growth in future
operating expenses.
As discussed in Note 3 to the financial statements, regulatory uncertainties
exist related to the Rocky Mountain pumped storage hydroelectric plant. In the
event the GPSC does not allow full recovery of the plant's costs, then the
portion not allowed may have to be written off. The Company's net investment in
the plant as of December 1996 is approximately $175 million.
Beginning in September 1996, OPC decreased its purchases of capacity under a
power supply agreement by 250 megawatts and has notified the Company of its
intent to decrease purchases of capacity by an additional 250 megawatts in
September 1997, and an additional 250 megawatts in September 1998. As a result,
the Company's capacity revenues declined approximately $8 million in 1996, and
will decline an additional $24 million in 1997, an additional $26 million in
1998, and an additional $19 million in 1999.
The Federal Energy Regulatory Commission (FERC) regulates wholesale rate
schedules and power sales contracts that the Company has with its sales for
resale customers. The FERC currently is reviewing the rate of return on common
equity included in these schedules and contracts and may require such returns to
be lowered, possibly retroactively. See Note 3 to the financial statements under
"FERC Review of Equity Returns" for additional information.
Compliance costs related to the Clean Air Act Amendments of 1990 (Clean Air
Act) could affect earnings if such costs are not fully recovered. The Clean Air
Act and other environmental issues are discussed later under "Environmental
Issues."
6
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 1996 Annual Report
The Energy Policy Act of 1992 (Energy Act) is having a dramatic 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 Company is positioning the business to meet the challenge of this
major change in the traditional practice 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. This enhances 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.
Also, electricity sales for resale rates are being driven down by wholesale
transmission access and numerous potential new energy suppliers, including power
marketers and brokers. The Company is aggressively working to maintain and
expand its share of wholesale sales in the Southeastern power markets.
The Company continues to compete with other electric suppliers within the
state. In Georgia, most new retail customers with at least 900 kilowatts of
connected load may choose their electricity supplier. Various federal and state
initiatives designed to promote wholesale and additional retail competition,
among other things, include proposals that would allow customers to choose
their electricity provider. As the initiatives materialize, the structure of
the utility industry could radically change. Certain initiatives could result
in a change in the ownership and/or operation of generation and transmission
facilities. Numerous issues must be resolved, including significant ones
relating to transmission pricing and recovery of stranded investments. Being
a low-cost producer could provide significant opportunities to increase market
share and profitability in markets that evolve with changing regulation.
Unless the Company remains a low-cost producer and provides quialty service,
the Company's retail energy sales growth could be limited, and this could
significantly erode earnings.
The Company is subject to the provisions of Financial Accounting Standards
Board (FASB) Statement No. 71, Accounting for the Effects of Certain Types of
Regulation. In the event that a portion of the Company's operations is no longer
subject to these provisions, the Company would be required to write off related
regulatory assets and liabilities, and determine if any other assets have been
impaired. See Note 1 to the financial statements under "Regulatory Assets and
Liabilities" for additional information.
The staff of the Securities and Exchange Commission has questioned certain
of the current accounting practices of the electric utility industry --
including the Company's -- regarding the recognition, measurement, and
classification of decommissioning costs for nuclear generating facilities in the
financial statements. In response to these questions, the FASB has decided to
review the accounting for liabilities related to closure and removal of
long-lived assets, including nuclear decommissioning. If the FASB issues new
accounting rules, the estimated costs of closing and removing the Company's
nuclear and other facilities may be required to be recorded as liabilities in
the Balance Sheets. Also, the annual provisions for such costs could change.
Because of the Company's current ability to recover closure and removal costs
through rates, these changes would not have a significant adverse effect on
results of operations. See Note 1 to the financial statements under
"Depreciation and Nuclear Decommissioning" for additional information.
FINANCIAL CONDITION
Plant Additions
In 1996 gross utility plant additions were $428 million. These additions were
primarily related to transmission and distribution facilities and to the
purchase of nuclear fuel. The funds needed for gross property additions are
currently provided from operations. The Statements of Cash Flows provide
additional details.
Financing Activities
In 1996, the Company continued to lower its financing costs by refinancing
higher-cost issues. New issues during 1994 through 1996 totaled $1.6 billion and
retirement or repayment of securities totaled $2.2 billion. The retirements
included the redemption of $131 million and $133 million in 1995 and 1994,
respectively, of first mortgage bonds with the proceeds from the Plant Scherer
Unit 4 sales. Composite financing rates for long-term debt
7
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 1996 Annual Report
and preferred stock for the years 1994 through 1996, as of year-end, were as
follows:
1996 1995 1994
---------------------------------
Composite interest rate
on long-term debt 6.39% 6.57% 7.14%
Composite preferred
stock dividend rate 6.34 6.73 7.11
- ----------------------------------------------------------------
The Company's current securities ratings are as follows:
Duff & Standard &
Phelps Moody's Poor's
------------------------------------
First Mortgage Bonds AA- A1 A+
Preferred Stock A+ a2 A
Unsecured Bonds A+ A2 A
Commercial Paper D1+ P1 A1
- -----------------------------------------------------------------
In August 1996, Georgia Power Capital Trust I (Trust I), of which the
Company owns all the common securities, issued $225 million of 7.75 percent
mandatorily redeemable preferred securities. Substantially all of the assets of
Trust I are $232 million aggregate principal amount of the Company's 7.75
percent Junior Subordinated Notes due June 30, 2036. In January 1997, Georgia
Power Capital Trust II (Trust II), of which the Company owns all the common
securities, issued $175 million of 7.60 percent mandatorily redeemable preferred
securities. Substantially all of the assets of Trust II are $180 million
aggregate principal amount of the Company's 7.60 percent Junior Subordinated
Notes due December 31, 2036.
Liquidity and Capital Requirements
Cash provided from operations decreased by $31 million in 1996, primarily due to
higher operating and maintenance expenses.
The Company estimates that construction expenditures for the years 1997
through 1999 will total $490 million, $479 million and $464 million,
respectively. Investments in transmission and distribution facilities,
enhancements to existing generating plants, additions of a co-owned combustion
turbine generating plant, and equipment to comply with the provisions of the
Clean Air Act are planned.
Cash requirements for improvement fund requirements, redemptions announced,
and maturities of long-term debt and preferred stock are expected to total $436
million during 1997 through 1999.
As a result of requirements by the Nuclear Regulatory Commission, the
Company has established external trust funds for the purpose of funding nuclear
decommissioning costs. For 1997 through 1999, the amount to be funded totals $24
million annually. For additional information concerning nuclear decommissioning
costs, see Note 1 to the financial statements under "Depreciation and Nuclear
Decommissioning."
Sources of Capital
The Company expects to meet future capital requirements primarily using funds
generated from operations and, if needed, by the issuance of new debt and equity
securities, term loans, and short-term borrowings. To meet short-term cash needs
and contingencies, the Company had approximately $1.1 billion of unused credit
arrangements with banks at the beginning of 1997. See Note 9 to the financial
statements under "Bank Credit Arrangements" for additional information.
The Company is required to meet certain coverage requirements specified in
its mortgage indenture and corporate charter to issue new first mortgage bonds
and preferred stock. The Company's ability to satisfy all coverage requirements
is such that it could issue new first mortgage bonds and preferred stock to
provide sufficient funds for all anticipated requirements.
Environmental Issues
In November 1990, the Clean Air Act was signed into law. Title IV of the Clean
Air Act -- the acid rain compliance provision of the law -- is having a
significant impact on the operating companies of Southern Company, including
Georgia Power. Specific reductions in sulfur dioxide and nitrogen oxide
emissions from fossil-fired generating plants are required in two phases. Phase
I compliance began in 1995 and initially affected 28 generating units in the
Southern electric system. As a result of Southern Company's compliance strategy,
an additional 22 generating units were brought into compliance with Phase I
requirements. Phase II compliance is required in 2000, and all fossil-fired
generating plants in the Southern electric system will be affected.
8
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 1996 Annual Report
In 1995, the Environmental Protection Agency (EPA) began issuing annual
sulfur dioxide emission allowances through the allowance trading program. An
emission allowance is the authority to emit one ton of sulfur dioxide during a
calendar year. The sulfur dioxide emission allowance program is expected to
minimize the cost of compliance. Southern Company's sulfur dioxide compliance
strategy is designed to use allowances as a compliance option.
Southern Company achieved Phase I sulfur dioxide compliance at the affected
units by switching to low-sulfur coal, which has required some equipment
upgrades. This compliance strategy resulted in unused emission allowances being
banked for later use. Construction expenditures for Georgia Power's Phase I
compliance totaled approximately $163 million.
For Phase II sulfur dioxide compliance, Southern Company could use emission
allowances, increase fuel switching, and/or install flue gas desulfurization
equipment at selected plants. Also, equipment to control nitrogen oxide
emissions will be installed on additional system fossil-fired units as required
to meet Phase II limits. Therefore, current compliance strategy could require
total Phase II estimated construction expenditures, for the Company, of
approximately $29 million of which $21 million remains to be spent. However, the
full impact of Phase II compliance cannot now be determined with certainty,
pending the continuing development of a market for emission allowances, the
completion of EPA regulations, and the possibility of new emission reduction
technologies.
An increase of up to 1 percent in Georgia Power's annual revenue
requirements from customers could be necessary to fully recover the cost of
compliance for both Phase I and Phase II of Title IV of the Clean Air Act.
Compliance costs include construction expenditures, increased costs for
switching to low-sulfur coal, and costs related to emission allowances.
A significant portion of costs related to the acid rain provision of the
Clean Air Act is expected to be recovered through existing ratemaking
provisions. However, there can be no assurance that all Clean Air Act costs will
be recovered.
The EPA and state environmental regulatory agencies are reviewing and
evaluating various matters including: revisions to the ambient air quality
standards for ozone and particulate matter; emission control strategies for
ozone nonattainment areas; additional controls for hazardous air pollutant
emissions; and hazardous waste disposal requirements. The impact of new
standards will depend on the development and implementation of applicable
regulations.
The Company must comply with other environmental laws and regulations that
cover the handling and disposal of hazardous waste. Under these various laws and
regulations, the Company could incur costs to clean up properties currently or
previously owned. The Company conducts studies to determine the extent of any
required clean-up costs and has recognized in the financial statements costs to
clean up known sites. These costs for the Company amounted to $2 million, $8
million and $8 million, in 1996, 1995, and 1994, respectively. Additional sites
may require environmental remediation for which the Company may be liable for a
portion of or all required clean-up costs. See Note 3 to the financial
statements under "Certain Environmental Contingencies" for information regarding
the Company's potentially responsible party status at a site in Brunswick,
Georgia and the status of sites listed on the State of Georgia's hazardous site
inventory.
Several major pieces of environmental legislation are being considered for
reauthorization or amendment by Congress. These include: the Clean Air Act; the
Clean Water Act; the Comprehensive Environmental Response, Compensation, and
Liability Act; the Resource Conservation and Recovery Act; the Toxic Substances
Control Act; and the Endangered Species Act. Changes to these laws could affect
many areas of the Company's operations. The full impact of any such changes
cannot be determined at this time.
Compliance with possible additional legislation related to global climate
change, electromagnetic fields and other environmental and health concerns could
significantly affect the Company. The impact of new legislation -- if any --
will depend on the subsequent development and implementation of applicable
regulations. In addition, the potential exists for liability as the result of
lawsuits alleging damages caused by electromagnetic fields.
9
<PAGE>
<TABLE>
<CAPTION>
STATEMENTS OF INCOME
For the Years Ended December 31, 1996, 1995, and 1994
Georgia Power Company 1996 Annual Report
- ----------------------------------------------------------------------------------------------------------------------------------
1996 1995 1994
- ----------------------------------------------------------------------------------------------------------------------------------
(in thousands)
Operating Revenues:
<S> <C> <C> <C>
Revenues $ 4,380,893 $ 4,328,432 $ 4,101,504
Revenues from affiliates 35,886 76,906 60,899
- ----------------------------------------------------------------------------------------------------------------------------------
Total operating revenues 4,416,779 4,405,338 4,162,403
- ----------------------------------------------------------------------------------------------------------------------------------
Operating Expenses:
Operation --
Fuel 835,194 900,973 870,653
Purchased power from non-affiliates 157,308 183,009 193,130
Purchased power from affiliates 229,324 131,740 158,063
Provision for separation benefits 39,099 10,607 82,238
Other 741,383 735,918 643,375
Maintenance 315,934 292,029 272,818
Depreciation and amortization 432,940 421,850 379,158
Amortization of deferred Plant Vogtle costs, net (Note 1) 136,650 124,454 74,888
Taxes other than income taxes 207,098 204,675 194,566
Federal and state income taxes 435,904 449,204 399,413
- ------------------------------------------------------------------------------------------------------------------------------------
Total operating expenses 3,530,834 3,454,459 3,268,302
- ----------------------------------------------------------------------------------------------------------------------------------
Operating Income 885,945 950,879 894,101
Other Income (Expense):
Allowance for equity funds used during construction 3,144 2,734 5,663
Equity in earnings of unconsolidated subsidiary (Note 4) 3,851 4,051 3,588
Interest income 5,333 5,524 3,254
Other, net (43,502) (8,973) 10,626
Income taxes applicable to other income 18,581 3,022 7,975
- ----------------------------------------------------------------------------------------------------------------------------------
Income Before Interest Charges 873,352 957,237 925,207
- ----------------------------------------------------------------------------------------------------------------------------------
Interest Charges and Other:
Interest on long-term debt 207,851 254,607 306,473
Allowance for debt funds used during construction (11,416) (12,081) (11,571)
Interest on interim obligations 15,478 21,463 17,529
Amortization of debt discount, premium, and expense, net 14,790 15,835 15,743
Other interest charges 6,338 11,399 23,183
Distributions on preferred securities of subsidiary companies 14,958 9,000 300
- ----------------------------------------------------------------------------------------------------------------------------------
Interest charges and other, net 247,999 300,223 351,657
- ----------------------------------------------------------------------------------------------------------------------------------
Net Income 625,353 657,014 573,550
Dividends on Preferred Stock 45,026 48,152 48,006
==================================================================================================================================
Net Income After Dividends on Preferred Stock $ 580,327 $ 608,862 $ 525,544
==================================================================================================================================
The accompanying notes are an integral part of these statements.
</TABLE>
10
<PAGE>
<TABLE>
<CAPTION>
STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 1996, 1995, and 1994
Georgia Power Company 1996 Annual Report
- ----------------------------------------------------------------------------------------------------------------------------
1996 1995 1994
- ----------------------------------------------------------------------------------------------------------------------------
(in thousands)
Operating Activities:
<S> <C> <C> <C>
Net income $ 625,353 $ 657,014 $ 573,550
Adjustments to reconcile net income to net
cash provided by operating activities --
Depreciation and amortization 521,086 527,310 484,032
Deferred income taxes and investment tax credits, net 35,700 37,150 33,567
Allowance for equity funds used during construction (3,144) (2,734) (5,663)
Amortization of deferred Plant Vogtle costs, net 136,650 124,454 74,888
Non-cash portion of separation benefits - - 68,599
Loss (gain) on asset sales 3,766 (23,588) (22,717)
Other, net 49,649 23,722 (72,597)
Changes in certain current assets and liabilities --
Receivables, net 9,421 (59,370) 67,218
Inventories 55,753 30,761 (63,545)
Payables (35,651) 45,882 5,409
Taxes accrued 11,766 11,373 (60,474)
Energy cost recovery, retail 679 42,576 55,505
Other (24,040) 3,473 (706)
- ---------------------------------------------------------------------------------------------------------------------------
Net cash provided from operating activities 1,386,988 1,418,023 1,137,066
- ----------------------------------------------------------------------------------------------------------------------------
Investing Activities:
Gross property additions (428,220) (480,449) (638,426)
Sales of property 3,319 131,099 132,644
Other (16,468) (42,579) (41,273)
- ----------------------------------------------------------------------------------------------------------------------------
Net cash used for investing activities (441,369) (391,929) (547,055)
- ----------------------------------------------------------------------------------------------------------------------------
Financing Activities:
Proceeds --
Preferred securities 225,000 - 100,000
First mortgage bonds 10,000 75,000 -
Pollution control bonds 112,825 504,700 527,210
Retirements --
Preferred stock (179,148) - -
First mortgage bonds (210,860) (505,789) (133,559)
Pollution control bonds (119,665) (504,810) (510,320)
Other long-term debt - (37,000) (10,187)
Interim obligations, net 30,166 (24,472) (57,425)
Special deposits -- redemption funds (44,454) - -
Capital distribution to parent company (250,000) - -
Payment of preferred stock dividends (46,911) (48,419) (47,147)
Payment of common stock dividends (475,500) (451,500) (429,300)
Miscellaneous (10,646) (17,413) (22,640)
- ----------------------------------------------------------------------------------------------------------------------------
Net cash used for financing activities (959,193) (1,009,703) (583,368)
- ----------------------------------------------------------------------------------------------------------------------------
Net Change in Cash and Cash Equivalents (13,574) 16,391 6,643
Cash and Cash Equivalents at Beginning of Year 28,930 12,539 5,896
- ----------------------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of Year $ 15,356 $ 28,930 $ 12,539
============================================================================================================================
Supplemental Cash Flow Information:
Cash paid during the year for --
Interest (net of amount capitalized) 249,434 $ 298,482 336,155
Income taxes (net of refunds) 373,886 404,129 386,653
- ----------------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these statements.
</TABLE>
11
<PAGE>
<TABLE>
<CAPTION>
BALANCE SHEETS
At December 31, 1996 and 1995
Georgia Power Company 1996 Annual Report
- ---------------------------------------------------------------------------------------------------------------
ASSETS 1996 1995
- ---------------------------------------------------------------------------------------------------------------
(in thousands)
Utility Plant:
<S> <C> <C>
Plant in service $ 14,769,573 $ 14,538,595
Less accumulated provision for depreciation 4,793,638 4,417,120
- ---------------------------------------------------------------------------------------------------------------
9,975,935 10,121,475
Nuclear fuel, at amortized cost 121,840 124,849
Construction work in progress (Note 4) 256,141 236,715
- ---------------------------------------------------------------------------------------------------------------
Total 10,353,916 10,483,039
- ---------------------------------------------------------------------------------------------------------------
Other Property and Investments:
Southern Electric Generating Company, at equity (Note 4) 26,032 27,232
Nuclear decommissioning trusts, at market 130,178 92,273
Miscellaneous 103,787 120,383
- ---------------------------------------------------------------------------------------------------------------
Total 259,997 239,888
- ---------------------------------------------------------------------------------------------------------------
Current Assets:
Cash and cash equivalents 15,356 28,930
Receivables-
Customer accounts receivable 392,328 418,749
Other accounts receivable 159,499 102,953
Affiliated companies 20,095 15,482
Accumulated provision for uncollectible accounts (4,000) (5,000)
Fossil fuel stock, at average cost 117,382 145,151
Materials and supplies, at average cost 258,820 286,804
Prepayments 109,771 107,764
Vacation pay deferred 39,965 35,543
- ---------------------------------------------------------------------------------------------------------------
Total 1,109,216 1,136,376
- ---------------------------------------------------------------------------------------------------------------
Deferred Charges:
Deferred charges related to income taxes (Note 8) 818,418 871,783
Deferred Plant Vogtle costs (Note 1) 170,988 307,638
Premium on reacquired debt, being amortized 166,670 174,018
Debt expense, being amortized 32,693 27,227
Miscellaneous 159,153 230,306
- ---------------------------------------------------------------------------------------------------------------
Total 1,347,922 1,610,972
- ---------------------------------------------------------------------------------------------------------------
Total Assets $ 13,071,051 $ 13,470,275
===============================================================================================================
The accompanying notes are an integral part of these statements.
12
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
BALANCE SHEETS
At December 31, 1996 and 1995
Georgia Power Company 1996 Annual Report
- -------------------------------------------------------------------------------------------------------------------
CAPITALIZATION AND LIABILITIES 1996 1995
- -------------------------------------------------------------------------------------------------------------------
(in thousands)
Capitalization (See accompanying statements):
<S> <C> <C>
Common stock equity $ 4,154,281 $ 4,299,012
Preferred stock 464,611 692,787
Company obligated mandatorily redeemable preferred securities
of subsidiaries substantially all of whose assets are junior
subordinated debentures or notes (Note 9) 325,000 100,000
Long-term debt 3,200,419 3,315,460
- -------------------------------------------------------------------------------------------------------------------
Total 8,144,311 8,407,259
- -------------------------------------------------------------------------------------------------------------------
Current Liabilities:
Preferred stock due within one year (Note 9) 49,028 -
Long-term debt due within one year (Note 9) 60,622 150,446
Notes payable to banks (Note 9) 207,300 178,000
Commercial paper (Note 9) 223,196 222,330
Accounts payable-
Affiliated companies 66,821 72,878
Other 263,093 316,278
Customer deposits 64,901 53,145
Taxes accrued-
Federal and state income 15,497 7,759
Other 100,661 96,633
Interest accrued 79,936 96,162
Vacation pay accrued 38,597 34,233
Miscellaneous 114,530 137,184
- -------------------------------------------------------------------------------------------------------------------
Total 1,284,182 1,365,048
- -------------------------------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes (Note 8) 2,522,945 2,510,458
Accumulated deferred investment tax credits 415,477 432,184
Deferred credits related to income taxes (Note 8) 382,381 410,016
Employee benefits provisions 186,319 182,082
Disallowed Plant Vogtle capacity buyback costs (Note 4) 57,250 58,514
Miscellaneous 78,186 104,714
- -------------------------------------------------------------------------------------------------------------------
Total 3,642,558 3,697,968
- -------------------------------------------------------------------------------------------------------------------
Commitments and Contingent Matters (Notes 1 through 7)
Total Capitalization and Liabilities $ 13,071,051 $ 13,470,275
===================================================================================================================
The accompanying notes are an integral part of these statements.
</TABLE>
13
<PAGE>
<TABLE>
<CAPTION>
STATEMENTS OF CAPITALIZATION
At December 31, 1996 and 1995
Georgia Power Company 1996 Annual Report
- ----------------------------------------------------------------------------------------------------------------------------------
1996 1995 1996 1995
- ----------------------------------------------------------------------------------------------------------------------------------
(in thousands) (percent of total)
Common Stock Equity:
Common stock, without par value --
Authorized -- 15,000,000 shares
<S> <C> <C> <C>
Outstanding -- 7,761,500 shares $ 344,250 $ 344,250
Paid-in capital 2,134,886 2,384,444
Premium on preferred stock 371 413
Retained earnings (Note 9) 1,674,774 1,569,905
- ----------------------------------------------------------------------------------------------------------------------------------
Total common stock equity 4,154,281 4,299,012 51.0% 51.1%
- ----------------------------------------------------------------------------------------------------------------------------------
Cumulative Preferred Stock, without par value:
Authorized -- 55,000,000 shares
Outstanding -- 16,111,964 shares
$100 stated value --
4.60% to 6.60% 117,787 117,787
7.72% to 7.80% 30,000 105,000
$25 stated value --
$1.90 to $2.125 190,852 295,000
Adjustable rate -- at January 1, 1997:
5.20% 100,000 100,000
5.66% 75,000 75,000
- ----------------------------------------------------------------------------------------------------------------------------------
Total cumulative preferred stock (annual dividend
requirement -- $32,580,000) 513,639 692,787
Less amount due within one year (Note 9) 49,028 -
- ----------------------------------------------------------------------------------------------------------------------------------
Cumulative preferred stock excluding amount due within one year 464,611 692,787 5.7 8.2
- ----------------------------------------------------------------------------------------------------------------------------------
Company Obligated Mandatorily
Redeemable Preferred Securities (Note 9):
$25 liquidation value -- 9% 100,000 100,000
$25 liquidation value -- 7.75% 225,000 -
- ----------------------------------------------------------------------------------------------------------------------------------
Total (annual distribution requirement -- $26,438,000) 325,000 100,000 4.0 1.2
- ----------------------------------------------------------------------------------------------------------------------------------
Long-Term Debt:
First mortgage bonds --
Maturity Interest Rates
March 1, 1996 4 3/4% - 150,000
April 1, 1998 5 1/2% 100,000 100,000
September 1, 1999 6 1/8% 195,000 195,000
March 1, 2000 6% 100,000 100,000
October 1, 2000 7% 100,000 100,000
2002 through 2005 6.07% to 6 7/8% 435,000 425,000
2008 6 7/8% 50,000 50,000
2022 through 2025 7.55% to 8 5/8% 534,508 595,368
- ----------------------------------------------------------------------------------------------------------------------------------
Total first mortgage bonds 1,514,508 1,715,368
Pollution control obligations (Note 9) 1,671,190 1,678,030
Other long-term debt (Note 9) 87,114 87,400
Unamortized debt discount, net (11,771) (14,892)
- ----------------------------------------------------------------------------------------------------------------------------------
Total long-term debt (annual interest
requirement -- $209,047,000) 3,261,041 3,465,906
Less amount due within one year (Note 9) 60,622 150,446
- ----------------------------------------------------------------------------------------------------------------------------------
Long-term debt excluding amount due within one year 3,200,419 3,315,460 39.3 39.5
- ----------------------------------------------------------------------------------------------------------------------------------
Total Capitalization $ 8,144,311 $ 8,407,259 100.0% 100.0%
==================================================================================================================================
The accompanying notes are an integral part of these statements.
</TABLE>
14
<PAGE>
<TABLE>
<CAPTION>
STATEMENTS OF RETAINED EARNINGS
For the Years Ended December 31, 1996, 1995, and 1994
Georgia Power Company 1996 Annual Report
- ----------------------------------------------------------------------------------------------------------------
1996 1995 1994
- ----------------------------------------------------------------------------------------------------------------
(in thousands)
<S> <C> <C> <C>
Balance at Beginning of Period $ 1,569,905 $ 1,412,543 $ 1,316,447
Net income after dividends on preferred stock 580,327 608,862 525,544
Cash dividends on common stock (475,500) (451,500) (429,300)
Preferred stock transactions, net 42 - (148)
- ----------------------------------------------------------------------------------------------------------------
Balance at End of Period (Note 9) $ 1,674,774 $ 1,569,905 $ 1,412,543
================================================================================================================
</TABLE>
<TABLE>
<CAPTION>
STATEMENTS OF PAID-IN CAPITAL
For the Years Ended December 31, 1996, 1995, and 1994
Georgia Power Company 1996 Annual Report
- ----------------------------------------------------------------------------------------------------------------------
1996 1995 1994
- ----------------------------------------------------------------------------------------------------------------------
(in thousands)
<S> <C> <C> <C>
Balance at Beginning of Period $ 2,384,444 $ 2,384,348 $ 2,384,348
Capital distribution to parent company (250,000) - -
Contributions to capital by parent company 442 96 -
- ----------------------------------------------------------------------------------------------------------------------
Balance at End of Period $ 2,134,886 $ 2,384,444 $ 2,384,348
======================================================================================================================
The accompanying notes are an integral part of these statements.
</TABLE>
15
<PAGE>
NOTES TO FINANCIAL STATEMENTS
Georgia Power Company 1996 Annual Report
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
General
The Company is a wholly owned subsidiary of Southern Company, which is the
parent company of five operating companies, Southern Company Services (SCS), a
system service company, Southern Communications Services (Southern
Communications), Southern Energy, Inc. (Southern Energy), Southern Nuclear
Operating Company (Southern Nuclear), The Southern Development and Investment
Group (Southern Development), and other direct and indirect subsidiaries. The
operating companies (Alabama Power Company, Georgia Power Company, Gulf Power
Company, Mississippi Power Company, and Savannah Electric and Power Company)
provide electric service in four Southeastern states. Contracts among the
operating companies -- dealing with jointly owned generating facilities,
interconnecting transmission lines, and the exchange of electric power -- are
regulated by the Federal Energy Regulatory Commission (FERC) or the Securities
and Exchange Commission (SEC). SCS provides, at cost, specialized services to
Southern Company and subsidiary companies. Southern Communications provides
digital wireless communications services to the operating companies and also
markets these services to the public within the Southeast. Southern Energy
designs, builds, owns, and operates power production and delivery facilities and
provides a broad range of energy related services in the United States and
international markets. Southern Nuclear provides services to Southern Company's
nuclear power plants. Southern Development develops new business opportunities
related to energy products and services.
Southern Company is registered as a holding company under the Public Utility
Holding Company Act of 1935 (PUHCA). Both Southern Company and its subsidiaries
are subject to the regulatory provisions of this act. The Company is also
subject to regulation by the FERC and the Georgia Public Service Commission
(GPSC). The Company follows generally accepted accounting principles (GAAP) and
complies with the accounting policies and practices prescribed by the respective
regulatory commissions. The preparation of financial statements in conformity
with GAAP requires the use of estimates, and the actual results may differ from
these estimates.
Certain prior years' data presented in the financial statements have been
reclassified to conform with current year presentation.
Regulatory Assets and Liabilities
The Company is subject to the provisions of Financial Accounting Standards Board
(FASB) Statement No. 71, Accounting for the Effects of Certain Types of
Regulation. Regulatory assets represent probable future revenues to the Company
associated with certain costs that are expected to be recovered from customers
through the ratemaking process. Regulatory liabilities represent probable future
reductions in revenues associated with amounts that are to be credited to
customers through the ratemaking process. Regulatory assets and (liabilities)
reflected in the Company's Balance Sheets at December 31 relate to the
following:
1996 1995
--------------------
(in millions)
--------------------
Deferred income taxes $ 818 $ 872
Deferred income tax credits (382) (410)
Deferred Plant Vogtle costs 171 308
Premium on reacquired debt 167 174
Corporate building lease 51 49
Demand-side program costs 44 79
Vacation pay 40 36
Postretirement benefits 38 53
Department of Energy assessments 32 33
Inventory conversions (18) (31)
Other, net 27 36
==============================================================
Total $ 988 $1,199
==============================================================
In the event that a portion of the Company's operations is no longer subject
to the provisions of Statement No. 71, the Company would be required to write
off related regulatory assets and liabilities. In addition, the Company would be
required to determine any impairment to other assets, including plant, and write
down the assets, if impaired, to their fair value.
16
<PAGE>
NOTES (continued)
Georgia Power Company 1996 Annual Report
Revenues and Fuel Costs
The Company accrues revenues for service rendered but unbilled at the end of
each fiscal period. Fuel costs are expensed as the fuel is used. The Company's
electric rates include provisions to adjust billings for fluctuations in fuel
and the energy component of purchased power costs. Revenues are adjusted for
differences between recoverable fuel costs and amounts actually recovered in
current rates.
The Company has a diversified base of customers. No single customer or
industry comprises 10 percent or more of revenues. In 1996, uncollectible
accounts continued to average less than 1 percent of revenues.
Fuel expense includes the amortization of the cost of nuclear fuel and a
charge, based on nuclear generation, for the permanent disposal of spent nuclear
fuel. Total charges for nuclear fuel included in fuel expense amounted to $78
million in 1996, $86 million in 1995, and $87 million in 1994. The Company has a
contract with the U.S. Department of Energy (DOE) that provides 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 and into 2008 at Plant Vogtle. Activities for adding dry cast storage
capacity at Plant Hatch by as early as 1999 are in progress.
Also, the Energy Policy Act of 1992 required the establishment in 1993 of a
Uranium Enrichment Decontamination and Decommissioning Fund, which is to be
funded in part by a special assessment on utilities with nuclear plants. This
fund will be used by the DOE for the decontamination and decommissioning of its
nuclear fuel enrichment facilities. The assessment will be paid over a 15-year
period, which began in 1993. The law provides that utilities will recover these
payments in the same manner as any other fuel expense. The Company -- based on
its ownership interests -- estimates its remaining liability under this law at
December 31, 1996, to be approximately $30 million. This obligation is recorded
in the accompanying Balance Sheets.
Depreciation and Nuclear Decommissioning
Depreciation of the original cost of depreciable utility plant in service is
provided primarily by using composite straight-line rates, which approximated
3.1 percent in 1996, 3.2 percent in 1995 and 3.1 percent in 1994. In addition,
the Company recorded accelerated depreciation of electric plant of $24 million
in 1996 and $6 million in 1995. The amount of such charges in the accumulated
provision for depreciation is $30 million at December 31, 1996. When property
subject to depreciation is retired or otherwise disposed of in the normal course
of business, its cost -- together with the cost of removal, less salvage -- is
charged to the accumulated provision for depreciation. Minor items of property
included in the original cost of the plant are retired when the related property
unit is retired. Depreciation expense includes an amount for the expected costs
of decommissioning nuclear facilities and removal of other facilities.
In 1988, the Nuclear Regulatory Commission (NRC) adopted regulations
requiring all licensees operating commercial nuclear power reactors to establish
a plan for providing, with reasonable assurance, funds for decommissioning. The
Company has established external trust funds to comply with the NRC's
regulations. Amounts previously recorded in internal reserves are being
transferred into the external trust funds over a set period of time as ordered
by the GPSC. Earnings on the trust funds are considered in determining
decommissioning expense. The NRC's minimum external funding requirements are
based on a generic estimate of the cost to decommission the radioactive portions
of a nuclear unit based on the size and type of reactor. The Company has filed
plans with the NRC to ensure that -- over time -- the deposits and earnings of
the external trust funds will provide the minimum funding amounts prescribed by
the NRC.
Site study cost is the estimate to decommission the facility as of the site
study year, and ultimate cost is the estimate to decommission the facility as of
the retirement
17
<PAGE>
NOTES (continued)
Georgia Power Company 1996 Annual Report
date. The estimated costs of decommissioning -- both site study costs and
ultimate costs at December 31, 1996 -- based on the Company's ownership
interests -- were as follows:
Plant Plant
Hatch Vogtle
--------------------
Site study basis (year) 1994 1994
Decommissioning periods:
Beginning year 2014 2027
Completion year 2027 2038
- ------------------------------------------------------------
(in millions)
Site study costs:
Radiated structures $294 $233
Non-radiated structures 41 52
============================================================
Total $335 $285
============================================================
(in millions)
Ultimate costs:
Radiated structures $781 $1,018
Non-radiated structures 111 230
- ------------------------------------------------------------
Total $892 $1,248
============================================================
(in millions)
Amount expensed in 1996 $ 11 $ 9
Accumulated provisions:
Balance in external trust funds $ 79 $ 51
Balance in internal reserves 27 13
============================================================
Total $106 $ 64
============================================================
Significant assumptions:
Inflation rate 4.4% 4.4%
Trust earnings rate 6.0 6.0
- ------------------------------------------------------------
Annual provisions for nuclear decommissioning are based on an annuity method
as approved by the GPSC. The decommissioning costs included in cost of service
are based on the higher of the costs to decommission the radioactive portions of
the plants based on 1994 site studies or the NRC minimum funding requirements.
The Company expects the GPSC to periodically review and adjust, if necessary,
the amounts collected in rates for the anticipated cost of decommissioning.
The decommissioning cost estimates are based on prompt dismantlement and
removal of the plant from service. The actual decommissioning costs may vary
from the above estimates because of changes in the assumed date of
decommissioning, changes in NRC requirements, changes in the assumptions used in
making estimates, changes in regulatory requirements, changes in technology, and
changes in costs of labor, materials, and equipment.
Income Taxes
The Company uses the liability method of accounting for deferred income taxes
and provides deferred income taxes for all significant income tax temporary
differences. Investment tax credits utilized are deferred and amortized to
income over the average lives of the related property.
Plant Vogtle Phase-In Plans
In 1987 and 1989, the GPSC ordered that the allowed costs of Plant Vogtle, a
two-unit nuclear facility of which Georgia Power owns 45.7 percent, be phased
into rates. Pursuant to the orders, the Company recorded a deferred return under
phase-in plans until October 1991 when the allowed investment was fully
reflected in rates. In 1991, the GPSC levelized the remaining Plant Vogtle
declining capacity buyback expenses over a six-year period. In addition, the
Company deferred certain Plant Vogtle operating expenses and financing costs
under accounting orders issued by the GPSC. These GPSC orders provide for the
recovery of deferred costs within 10 years.
Allowance for Funds Used During Construction (AFUDC)
AFUDC represents the estimated debt and equity costs of capital funds that are
necessary to finance the construction of new facilities. While cash is not
realized currently from such allowance, it increases the revenue requirement
over the service life of the plant through a higher rate base and higher
depreciation expense. For the years 1996, 1995 and 1994, the average AFUDC rates
were 6.59 percent, 6.53 percent and 6.18 percent, respectively. AFUDC, net of
taxes, as a percentage of net income after dividends on preferred stock, was
less than 2.5 percent for 1996, 1995, and 1994.
18
<PAGE>
NOTES (continued)
Georgia Power Company 1996 Annual Report
Utility Plant
Utility plant is stated at original cost with the exception of Plant Vogtle,
which is stated at cost less regulatory disallowances. Original cost includes:
materials; labor; payroll-related costs such as taxes, pensions, and other
benefits; and the cost of funds used during construction. The cost of
maintenance, repairs, and replacement of minor items of property is charged to
maintenance expense. The cost of replacements of property (exclusive of minor
items of property) is charged to utility plant.
Cash and Cash Equivalents
For purposes of the 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
The Company's financial instruments for which the carrying amounts did not
approximate fair value at December 31 were as follows:
Carrying Fair
Amount Value
--------------------------
Long-term debt: (in millions)
At December 31, 1996 $3,174 $3,206
At December 31, 1995 3,378 3,487
Preferred Securities:
At December 31, 1996 325 333
At December 31, 1995 100 114
- ---------------------------------------------------------------
The fair values for securities were based on either closing market prices or
closing prices of comparable instruments.
Materials and Supplies
Generally, materials and supplies include the cost of transmission, distribution
and generating plant materials. Materials are charged to inventory when
purchased and then expensed or capitalized to plant, as appropriate, when
installed.
2. RETIREMENT BENEFITS
Pension Plan
The Company has a defined benefit, trusteed,
non-contributory pension plan covering substantially all regular employees.
Benefits are based on one of the following formulas: years of service and final
average pay or years of service and a flat-dollar benefit. The Company uses the
"entry age normal method with a frozen initial liability" actuarial method for
funding purposes, subject to limitations under federal income tax regulations.
Amounts funded to the pension trusts are primarily invested in equity and
fixed-income securities. FASB Statement No. 87, Employers' Accounting for
Pensions, requires use of the "projected unit credit" actuarial method for
financial reporting purposes.
Postretirement Benefits
The Company also provides certain medical care and life insurance benefits for
retired employees. Substantially all employees may become eligible for these
benefits when they retire. Qualified trusts are funded to the extent deductible
under federal income tax regulations and to the extent required by the GPSC and
the FERC. During 1996 and 1995, the Company funded $25 million and $21 million,
respectively, to the qualified trusts. Amounts funded are primarily invested in
debt and equity securities.
FASB Statement No. 106, Employers' Accounting for Postretirement Benefits
Other Than Pensions, requires that medical care and life insurance benefits for
retired employees be accounted for on an accrual basis using a specified
actuarial method, "benefit/years-of-service." In October 1993, the GPSC ordered
the Company to phase in the adoption of Statement No. 106 to cost of service
over a five-year period, whereby one-fifth of the additional cost was expensed
in 1993, and the remaining additional costs were deferred. An additional
one-fifth of the costs will be expensed each succeeding year until the costs are
fully reflected in cost of service in 1997. The cost deferred during the
five-year period will be amortized to expense over a 15-year period beginning in
1998.
19
<PAGE>
NOTES (continued)
Georgia Power Company 1996 Annual Report
Funded Status and Cost of Benefits
The following tables show actuarial results and assumptions for pension and
postretirement benefits as computed under the requirements of FASB Statement
Nos. 87 and 106, respectively. The funded status of the plans at December 31 was
as follows:
Pension
---------------------
1996 1995
---------------------
(in millions)
---------------------
Actuarial present value of
benefit obligations:
Vested benefits $ 806 $ 830
Non-vested benefits 52 43
- --------------------------------------------------------------
Accumulated benefit obligation 858 873
Additional amounts related
to projected salary increases 314 290
- ---------------------------------------------------------------
Projected benefit obligation 1,172 1,163
Less:
Fair value of plan assets 1,797 1,688
Unrecognized net gain (591) (465)
Unrecognized prior service cost 56 26
Unrecognized transition asset (47) (52)
- ---------------------------------------------------------------
Prepaid asset recognized in
the Balance Sheets $ 43 $ 34
===============================================================
Postretirement
Benefits
---------------------
1996 1995
---------------------
(in millions)
Actuarial present value of
benefit obligation:
Retirees and dependents $217 $214
Employees eligible to retire 29 16
Other employees 184 188
- ---------------------------------------------------------------
Accumulated benefit obligation 430 418
Less:
Fair value of plan assets 112 81
Unrecognized net loss 50 44
Unrecognized transition
obligation 157 186
- ---------------------------------------------------------------
Accrued liability recognized in the
Balance Sheets $111 $ 107
===============================================================
In 1995, the Company announced a cost sharing program for postretirement
benefits. The program establishes limits on amounts the Company will pay to
provide future retiree postretirement benefits. This change reduced the 1995
accumulated postretirement benefit obligation by approximately $97 million.
The weighted average rates used in actuarial calculations were:
1996 1995 1994
- ----------------------------------------------------------------
Discount 7.8% 7.3% 8.0%
Annual salary increase 5.3 4.8 5.5
Long-term return on
plan assets 8.5 8.5 8.5
- ----------------------------------------------------------------
An additional assumption used in measuring the accumulated postretirement
medical benefit obligation was a weighted average medical care cost trend rate
of 9.3 percent for 1996, decreasing gradually to 5.8 percent through the year
2005 and remaining at that level thereafter. An annual increase in the assumed
medical care cost trend rate of 1 percent would increase the accumulated benefit
obligation as of December 31, 1996, by $42 million and the aggregate of the
service and interest cost components of the net postretirement cost by $4
million.
The components of the plans' net costs are shown below:
Pension
----------------------------
1996 1995 1994
----------------------------
(in millions)
Benefits earned during the year $ 35 $ 33 $ 34
Interest cost on projected
benefit obligation 86 78 71
Actual (return) loss on plan assets (202) (317) 35
Net amortization (deferral) 62 185 (160)
- -----------------------------------------------------------------
Net pension cost $ (19) $ (21) $ (20)
=================================================================
Net pension costs were negative in 1996, 1995 and 1994. Of net pension
amounts recorded, $14 million in 1996 and $15 million in 1995 and 1994 were
recorded as a reduction to operating expense, and the remainder was recorded as
a reduction to construction and other accounts.
20
<PAGE>
NOTES (continued)
Georgia Power Company 1996 Annual Report
Postretirement Benefits
1996 1995 1994
-------------------------
(in millions)
Benefits earned during the year $ 9 $13 $15
Interest cost on accumulated
benefit obligation 30 34 33
Amortization of transition
obligation 9 16 15
Actual (return) loss on plan
assets (6) (8) 1
Net amortization (deferral) 3 4 (3)
- ---------------------------------------------------------------
Net postretirement cost $45 $59 $61
===============================================================
Of the above net postretirement benefit costs recorded, $29 million in 1996,
$33 million in 1995, and $28 million in 1994 were charged to operating expenses.
In addition, $3 million in 1996, $11 million in 1995, and $18 million in 1994
were deferred, and the remainder was charged to construction and other accounts.
During 1996, the Company expensed an additional $19 million due to an adjustment
to amounts previously deferred under the GPSC order as a result of changes in
the postretirement benefit plan.
Work Force Reduction Programs
The Company has incurred costs for work force reduction programs. The costs
related to these programs were $39 million in 1996, $11 million in 1995 and $82
million in 1994. Additionally, the Company recognized $9 million in 1996, $3
million in 1995, and $8 million in 1994 for its share of costs associated with
SCS's work force reduction programs.
3. REGULATORY AND LITIGATION MATTERS
Retail Accounting Order
On February 16, 1996, the GPSC approved a three-year accounting order for the
Company. Under the order, effective January 1, 1996, the Company's earnings are
evaluated against a retail return on common equity range of 10 percent to 12.5
percent. Earnings in excess of 12.5 percent will be used to accelerate the
amortization of regulatory assets or depreciation of electric plant. At its
option, the Company may also recognize accelerated amortization or depreciation
of assets within the allowed return on common equity range. The Company is
required to absorb cost increases of approximately $29 million annually during
the order's three-year operation, including $14 million annually of accelerated
depreciation of electric plant. During the order's operation, the Company will
not file for a general base rate increase unless its projected retail return on
common equity falls below 10 percent. Under the approved order, on July 1, 1998
the Company will make a general rate case filing in response to which the GPSC
would be expected either to continue the provisions of the accounting order or
adopt different ones. The Company's 1996 retail return on common equity was
within the 10 percent to 12.5 percent range.
In November 1996, on appeal by a consumer group, the Superior Court of
Fulton County, Georgia, reversed the GPSC's accounting order and remanded the
matter to the GPSC. The Court found that statutory requirements applicable to
rate cases should have been, but were not, followed. The GPSC subsequently
appealed the Superior Court's decision. In December 1996, the Company also filed
for an appeal. The Company is continuing to recognize expenses in accordance
with the accounting order while it is under appeal.
Rocky Mountain Plant Status
In its 1985 financing order, the GPSC concluded that completion of the Rocky
Mountain pumped storage hydroelectric plant in 1991, as then planned, was not
economically justifiable and reasonable and withheld authorization for the
Company to spend funds from approved securities issuances on that plant. AFUDC
accrued on the Rocky Mountain plant was not credited to income or included in
the plant's cost since December 1985. In 1988, the Company and OPC entered into
a joint ownership agreement for OPC to assume responsibility for the
construction and operation of the plant, as discussed in Note 6. In 1995, the
plant went into commercial operation. However, full recovery of the Company's
25.4 percent ownership interest depends on the GPSC's treatment of the plant's
costs and disposition of the plant's capacity output. In June 1996, the GPSC
initiated a review of the Rocky Mountain pumped storage hydroelectric plant. In
the event the GPSC does not allow full recovery of the plant's costs, then the
portion not allowed may have to be written off. At December 31, 1996, the
Company's net investment in the plant was approximately $175 million.
The final outcome of this matter cannot now be determined. Accordingly, no
provision for any write-down of the investment in the plant has been made.
21
<PAGE>
NOTES (continued)
Georgia Power Company 1996 Annual Report
Demand-Side Conservation Programs
In October 1993, a Superior Court of Fulton County, Georgia, judge ruled that
rate riders previously approved by the GPSC for recovery of the Company's costs
incurred in connection with demand-side conservation programs were unlawful. The
Company suspended collection of the demand-side conservation costs and appealed
the court's decision to the Georgia Court of Appeals. The Company deferred costs
related to these programs under an accounting order approved by the GPSC until
December 1994, when the Company resumed collection under the rate riders after
the Georgia Court of Appeals upheld their legality. In August 1995, the GPSC
ordered the Company to discontinue its current demand-side conservation programs
by the end of 1995. The rate riders will remain in effect until costs deferred
are collected, which is expected to be by the end of 1997.
Under the Retail Accounting Order approved February 16, 1996, the Company
will recognize approximately $29 million of deferred program costs over a
three-year period which will not be recovered through the riders.
FERC Review of Equity Returns
In May 1991, the FERC ordered that hearings be conducted concerning the
reasonableness of the Southern electric system's wholesale rate schedules and
contracts that have a return on common equity of 13.75 percent or greater. The
contracts that could be affected by the hearings include substantially all of
the transmission, unit power, long-term power, and other similar contracts.
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.
In August 1994, the FERC instituted another proceeding based on
substantially the same issues as in the 1991 proceeding. In November 1995, a
FERC administrative law judge issued an opinion that the FERC staff failed to
meet its burden of proof, and therefore no change in the equity return was
necessary. The FERC staff has filed exceptions to the administrative law judge's
opinion, and the matter remains pending before the FERC.
If the rates of return on common equity recommended by the FERC staff were
applied to all the schedules and contracts involved in both proceedings, as well
as certain other contracts that reference these proceedings in determining
return on common equity and if refunds were ordered, the amount of refunds could
range up to approximately $61 million at December 31, 1996. However, management
believes that rates are not excessive, and that refunds are not justified.
Certain Environmental Contingencies
In January 1995, the Company and four other unrelated entities were notified by
the EPA that they have been designated as potentially responsible parties under
the Comprehensive Environmental Response, Compensation and Liability Act with
respect to a site in Brunswick, Georgia. As of December 31, 1996, the Company
has recognized approximately $5 million in expenses associated with this site.
This represents the Company's agreed upon share of removal and remedial
investigation and feasibility study costs. The final outcome of this matter
cannot now be determined. However, based on the nature and extent of the
Company's activities relating to the site, management believes that the
Company's portion of any remaining remediation costs should not be material.
In compliance with the Georgia Hazardous Site Response Act of 1993, the
State of Georgia was required to compile an inventory of all known or suspected
sites where hazardous wastes, constituents or substances have been disposed of
or released in quantities deemed reportable by the State. In developing this
list, the State identified several hundred properties throughout the State,
including 25 sites which may require environmental remediation that were either
previously or are currently owned by the Company. The majority of these sites
are electrical power substations and power generation facilities. The Company
has remediated seven electrical substations on the list at a cost of
approximately $1 million. In addition, the Company has recognized approximately
$16 million in expenses through December 31, 1996 for the assessment of the
remaining sites on the list and the anticipated clean-up cost for 13 sites that
the Company plans to remediate. The accrued costs for environmental remediation
obligations are not discounted to their present value. Any cost of remediating
22
<PAGE>
NOTES (continued)
Georgia Power Company 1996 Annual Report
the remaining sites cannot presently be determined until such studies are
completed for each site and the State of Georgia determines whether remediation
is required. If all listed sites were required to be remediated, the Company
could incur expenses of up to approximately $15 million in additional clean-up
costs and construction expenditures of up to approximately $65 million to
develop new waste management facilities or install additional pollution control
devices.
Wholesale Litigation
In July 1994, Oglethorpe Power Corporation (OPC) and the Municipal Electric
Authority of Georgia (MEAG) filed a joint complaint with the FERC seeking to
recover from the Company an aggregate of approximately $16.5 million in alleged
partial requirements rates overcharges, plus approximately $6.3 million in
interest. OPC and MEAG claimed that the Company improperly reflected in such
rates costs associated with capacity that had previously been sold to Gulf
States pursuant to a unit power sales contract or, alternatively, that they
should be allocated a portion of the proceeds received by the Company as a
result of a settlement with Gulf States of litigation arising out of such
contract. In November 1996, the Company reached a settlement with OPC, MEAG and
the City of Dalton to pay the parties an aggregate of $14 million. The
settlement has been approved by the FERC.
In May 1996, MEAG filed a complaint with the FERC seeking termination as of
December 31, 1996 of the partial requirements tariff pursuant to which the
Company currently sells wholesale energy to MEAG. The complaint also sought
refunds in an unspecified amount as a result of alleged overcharges by the
Company under the tariff for the years 1993 through 1996. In June 1996, the
Company filed a response with the FERC requesting that its partial requirements
service obligation to MEAG be terminated as of the date sought by MEAG. On
January 10, 1997, the Company and MEAG reached an agreement to enter into a new
power supply relationship which would replace in their entirety the partial
requirements tariff and the scheduling services agreement between the Company
and MEAG. The agreement required the parties to formalize a new contractual
relationship and within approximately 45 days file the new contract with the
FERC for approval. Under the agreement, the Company does not owe MEAG any
refunds for alleged overcharges for the years specified.
Nuclear Performance Standards
In October 1989, the GPSC adopted a nuclear performance standard for the
Company's nuclear generating units under which the performance of plants Hatch
and Vogtle will be evaluated every three years. The performance standard is
based on each unit's capacity factor as compared to the average of all
comparable U.S. nuclear units operating at a capacity factor of 50 percent or
higher during the three-year period of evaluation. Depending on the performance
of the units, the Company could receive a monetary reward or penalty under the
performance standards criteria.
The first evaluation was conducted in 1993 for performance during the
1990-92 period. The GPSC approved a performance reward of approximately $8.5
million for the Company. This reward was collected through the retail fuel cost
recovery provision and recognized in income over a 36-month period which ended
in October 1996. In January 1997, the GPSC approved a performance award of
approximately $11.7 million for performance during the 1993-95 period. This
reward will be collected through the retail fuel cost recovery provision and
recognized in income over a 36-month period beginning January 1997.
4. COMMITMENTS
Construction Program
While the Company has no traditional baseload generating plants under
construction, the construction of one jointly owned combustion turbine peaking
unit was completed in January 1997. In addition, significant construction of
transmission and distribution facilities, and projects to upgrade and extend the
useful life of generating plants will continue. The Company currently estimates
property additions to be approximately $490 million in 1997, $479 million in
1998, and $464 million in 1999. The estimates for property additions for the
three-year period include $31 million committed to meeting the requirements of
the Clean Air Act.
The construction program is subject to periodic review and revision, and
actual construction costs may vary from estimates because of numerous factors,
including, but not limited to, changes in business conditions, load growth
estimates, environmental regulations, and regulatory requirements.
23
<PAGE>
NOTES (continued)
Georgia Power Company 1996 Annual Report
Fuel Commitments
To supply a portion of the fuel requirements of its generating plants, the
Company has entered into various long-term commitments for the procurement of
fossil and nuclear fuel. In most cases, these contracts contain provisions for
price escalations, minimum purchase levels and other financial commitments.
Total estimated long-term fossil and nuclear fuel commitments at December 31,
1996 were as follows:
Minimum
Year Obligations
----------------------
(in millions)
1997 $ 833
1998 679
1999 512
2000 423
2001 358
2002 and beyond 1,722
- ---------------------------------------------------------------
Total minimum obligations $ 4,527
===============================================================
Additional commitments for coal and for nuclear fuel will be required in the
future to supply the Company's fuel needs.
Purchase Power Commitments
In connection with the joint ownership arrangement for Plant Vogtle, discussed
in Note 6, the Company has made commitments to purchase declining fractions of
OPC's and MEAG's capacity and energy from this plant. The declining commitments
were in effect during periods of up to seven years following commercial
operation and ended in 1996. The commitments regarding a portion of a 5 percent
interest in Plant Vogtle owned by MEAG are in effect until the latter of the
retirement of the plant or the latest stated maturity date of MEAG's bonds
issued to finance such ownership interest. The payments for capacity are
required whether or not any capacity is available. The energy cost is a function
of each unit's variable operating costs. Except as noted below, the cost of such
capacity and energy is included in purchased power from non-affiliates in the
Company's Statements of Income. Capacity payments totaled $68 million, $76
million, and $129 million in 1996, 1995, and 1994, respectively. The current
projected Plant Vogtle capacity payments are:
Year Amounts
----------------------
(in millions)
1997 $ 58
1998 60
1999 62
2000 63
2001 62
2002 and beyond 858
- ---------------------------------------------------------------
Total $ 1,163
==============================================================
Portions of the payments noted above relate to costs in excess of Plant
Vogtle's allowed investment for ratemaking purposes. The present value of these
portions was written off in 1987 and 1990.
As discussed in Note 1, the Plant Vogtle declining capacity buyback expense
is being levelized over a six-year period which began in October 1991.
The Company and an affiliate, Alabama Power Company, own equally all of the
outstanding capital stock of Southern Electric Generating Company (SEGCO), which
owns electric generating units with a total rated capacity of 1,020 megawatts,
as well as associated transmission facilities. The capacity of the units has
been sold equally to the Company and Alabama Power under a contract which, in
substance, requires payments sufficient to provide for the operating expenses,
taxes, debt service and return on investment, whether or not SEGCO has any
capacity and energy available. The term of the contract extends automatically
for two-year periods, subject to either party's right to cancel upon two year's
notice. The Company's share of expenses included in purchased power from
affiliates in the Statements of Income, is as follows:
1996 1995 1994
---------------------------------
(in millions)
Energy $47 $44 $43
Capacity 30 29 33
- --------------------------------------------------------------
Total $77 $73 $76
==============================================================
Kilowatt-hours 2,780 2,391 2,429
- --------------------------------------------------------------
24
<PAGE>
NOTES (continued)
Georgia Power Company 1996 Annual Report
At December 31, 1996, the capitalization of SEGCO consisted of $52 million
of equity and $76 million of long-term debt on which the annual interest
requirement is $5 million.
The Company has entered into a 30-year purchase power agreement, scheduled
to begin in June 1998, for electricity during peaking periods from a planned 300
megawatt cogeneration facility. Capacity and fixed operation and maintenance
(O&M) payments are subject to reductions for failure to meet minimum capacity
output. Estimated capacity and fixed O&M payments are as follows:
Year Amounts
----------------------
(in millions)
1998 $ 13
1999 15
2000 15
2001 15
2002 and beyond 320
- ---------------------------------------------------------------
Total $ 378
===============================================================
Operating Leases
The Company has entered into coal rail car rental agreements with various terms
and expiration dates. These expenses totaled $11 million, $12 million, and $13
million for 1996, 1995, and 1994, respectively. At December 31, 1996, estimated
minimum rental commitments for these noncancelable operating leases were as
follows:
Year Amounts
----------------------
(in millions)
1997 $ 11
1998 10
1999 10
2000 10
2001 10
2002 and beyond 121
- ---------------------------------------------------------------
Total $ 172
===============================================================
5. NUCLEAR INSURANCE
Under the Price-Anderson Amendments Act of 1988, the Company maintains
agreements of indemnity with the NRC that, together with private insurance,
cover third-party liability arising from any nuclear incident occurring at the
Company's nuclear power plants. The act provides funds up to $8.9 billion for
public liability claims that could arise from a single nuclear incident. Each
nuclear plant is insured against this liability to a maximum of $200 million by
private insurance, with the remaining coverage provided by a mandatory program
of deferred premiums that could be assessed, after a nuclear incident, against
all owners of nuclear reactors. The Company could be assessed up to $79 million
per incident for each licensed reactor it operates but not more than an
aggregate of $10 million per incident to be paid in a calendar year for each
reactor. Such maximum assessment for the Company, excluding any applicable state
premium taxes, -- based on its ownership and buyback interests -- is $162
million per incident but not more than an aggregate of $20 million to be paid
for each incident in any one year.
The Company is a member of Nuclear 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 assessment in the event that losses exceed accumulated
reserve funds. The Company's maximum annual assessment is limited to $11 million
under current policies.
Additionally, the Company has policies that currently provide
decontamination, excess property insurance, and premature decommissioning
coverage up to $2.25 billion for losses in excess of the $500 million NML
coverage. This excess insurance is provided by Nuclear Electric Insurance
Limited (NEIL), a mutual insurance company.
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 $2.8 million per week for the second and third years.
Under each of the NEIL policies, members are subject to assessments if
losses each year exceed the accumulated funds available to the insurer under
that policy. The maximum annual assessments under the current policies for the
Company would be $16 million for excess property damage and $12 million for
replacement power.
25
<PAGE>
NOTES (continued)
Georgia Power Company 1996 Annual Report
For all on-site property damage insurance policies for commercial nuclear
power plants, the NRC requires that the proceeds of such policies issued or
renewed on or after April 2, 1991, shall be dedicated first for the sole purpose
of placing the reactor in a safe and stable condition after an accident. Any
remaining proceeds are to be applied next toward the costs of decontamination
and debris removal operations ordered by the NRC, and any further remaining
proceeds are to be paid either to the Company or to its bond trustees as may be
appropriate under the policies and applicable trust indentures.
The Company participates in an insurance program for nuclear workers that
provides coverage for worker tort claims filed for bodily injury caused at
commercial nuclear power plants. In the event that claims for this insurance
exceed the accumulated reserve funds, the Company could be subject to a maximum
total assessment of $6 million.
All retrospective assessments, whether generated for liability, property or
replacement power, may be subject to applicable state premium taxes.
6. FACILITY SALES AND JOINT OWNERSHIP AGREEMENTS
The Company has sold undivided interests in plants Hatch, Wansley, Vogtle, and
Scherer Units 1 and 2, together with transmission facilities, to OPC, an
electric membership generation and transmission corporation; MEAG, a public
corporation and an instrumentality of the state of Georgia; and the City of
Dalton, Georgia. The Company has sold an interest in Plant Scherer Unit 3 to
Gulf Power Company, an affiliate. Additionally, in 1995 the Company completed
the last 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 $808 million. FP&L now owns approximately
76.4 percent of the unit, with JEA owning the remainder.
The Scherer Unit 4 transactions were as follows:
Closing Percent After-Tax
Date Capacity Ownership Amount Gain
- ---------------------------------------------------------------
(in megawatts) (in millions)
July 1991 290 35.46% $ 291 $ 14
June 1993 258 31.44 253 18
June 1994 135 16.55 133 11
June 1995 135 16.55 131 12
- ---------------------------------------------------------------
Total 818 100.00% $ 808 $ 55
===============================================================
Except as otherwise noted, the Company has contracted to operate and
maintain all jointly owned facilities. The Company includes its proportionate
share of plant operating expenses in the corresponding operating expenses in the
Statements of Income.
As discussed in Note 3, the Company owns 25.4 percent of the Rocky Mountain
pumped storage hydroelectric plant, which began commercial operation in 1995.
OPC owns the remainder, and is the operator of the plant.
The Company owns six of eight 80 megawatt combustion turbine generating
units and 75 percent of the related common facilities at Plant McIntosh.
Savannah Electric and Power Company, an affiliate, owns the remainder and
operates the plant. Four of the Company's six units began commercial operation
during 1994, and the remaining two units began commercial operation in 1995.
The Company and Florida Power Corporation (FPC) jointly own a 150 megawatt
combustion turbine unit at Intercession City, Florida, near Orlando. The unit
began commercial operation in January 1997, and is operated by FPC. The Company
owns a one-third interest in the unit, with use of 100 percent of the unit's
capacity from June through September. FPC has the capacity the remainder of the
year. The Company's investment in the unit is approximately $13 million.
At December 31, 1996, the Company's percentage ownership and investment
(exclusive of nuclear fuel) in
26
<PAGE>
NOTES (continued)
Georgia Power Company 1996 Annual Report
jointly owned facilities in commercial operation, were as follows:
Total
Nameplate Company
Facility (Type) Capacity Ownership
- -----------------------------------------------------------------
(megawatts)
Plant Vogtle (nuclear) 2,320 45.7%
Plant Hatch (nuclear) 1,630 50.1
Plant Wansley (coal) 1,779 53.5
Plant Scherer (coal)
Units 1 and 2 1,636 8.4
Unit 3 818 75.0
Plant McIntosh
Common Facilities N/A 75.0
(combustion-turbine)
Rocky Mountain 848 25.4
(pumped storage)
- -----------------------------------------------------------------
Accumulated
Facility (Type) Investment Depreciation
- ----------------------------------------------------------------
(in millions)
Plant Vogtle (nuclear) $3,299* $843
Plant Hatch (nuclear) 854 436
Plant Wansley (coal) 301 134
Plant Scherer (coal)
Units 1 and 2 112 42
Unit 3 542 150
Plant McIntosh
Common Facilities
(combustion-turbine) 19 1
Rocky Mountain
(pumped storage) 202 27
- ----------------------------------------------------------------
* Investment net of write-offs.
7. LONG-TERM POWER SALES AGREEMENTS
The Company and the operating subsidiaries of Southern Company have long-term
contractual agreements for the sale of capacity and energy to non-affiliated
utilities located outside the system's service area. These agreements consist of
firm unit power sales pertaining to capacity from specific generating units. The
Company also had agreements for non-firm sales, which expired in 1994, based on
the capacity of the Southern system. Because energy is generally sold at cost
under these agreements, it is primarily the capacity revenues that affect the
Company's profitability.
The Company's capacity revenues were as follows:
Year Unit Power Sales Non-firm Sales
- -----------------------------------------------------------------
(in millions) (megawatts) (in millions) (megawatts)
1996 $ 41 173 $ - -
1995 53 248 - -
1994 75 403 9 101
- -----------------------------------------------------------------
Unit power from specific generating plants is being sold to FP&L, FPC, JEA,
and the City of Tallahassee, Florida. Under these agreements, the Company sold
approximately 173 megawatts of capacity in 1996 and is scheduled to sell
approximately 159 megawatts of capacity in 1997 through 1999, and in 2000, 126
megawatts will be sold. After 2000, capacity sales will decline to approximately
103 megawatts -- unless reduced by FP&L, FPC, and JEA -- until the expiration of
the contracts in 2010.
Long-term non-firm power of 200 megawatts was sold by the Southern system in
1994 to FPC, of which the Company's share was 101 megawatts, under a contract
that expired at the end of 1994. Sales under these long-term non-firm power
sales agreements were made from available power pool energy, and the revenues
from the sales were shared by the operating affiliates.
8. INCOME TAXES
At December 31, 1996, tax-related regulatory assets were $818 million and
tax-related regulatory liabilities were $382 million. The assets are
attributable to tax benefits flowed through to customers in prior years and to
taxes applicable to capitalized AFUDC. The liabilities are attributable to
deferred taxes previously recognized at rates higher than current enacted tax
law and to unamortized investment tax credits.
27
<PAGE>
NOTES (continued)
Georgia Power Company 1996 Annual Report
Details of the federal and state income tax provisions are as follows:
1996 1995 1994
-------------------------------
Total provision for income taxes: (in millions)
Federal:
Currently payable $ 325 $349 $306
Deferred -
Current year 70 84 86
Reversal of prior years (41) (55) (57)
Deferred investment tax
credits - 1 (1)
- -----------------------------------------------------------------
354 379 334
- -----------------------------------------------------------------
State:
Currently payable 56 60 52
Deferred -
Current year 12 15 15
Reversal of prior years (5) (8) (10)
- -----------------------------------------------------------------
63 67 57
- -----------------------------------------------------------------
Total 417 446 391
- -----------------------------------------------------------------
Less:
Income taxes credited
to other income (19) (3) (8)
=================================================================
Total income taxes
charged to operations $ 436 $449 $399
=================================================================
The tax effects of temporary differences between the carrying amounts of
assets and liabilities in the financial statements and their respective tax
bases, which give rise to deferred tax assets and liabilities, are as follows:
1996 1995
-------------------
(in millions)
Deferred tax liabilities:
Accelerated depreciation $ 1,736 $1,630
Property basis differences 1,038 1,074
Deferred Plant Vogtle costs 54 100
Premium on reacquired debt 67 70
Deferred regulatory costs 21 38
Other 32 29
- ----------------------------------------------------------------
Total 2,948 2,941
- ----------------------------------------------------------------
Deferred tax assets:
Other property basis differences 225 239
Federal effect of state deferred taxes 100 97
Other deferred costs 93 83
Disallowed Plant Vogtle buybacks 24 25
Accrued interest 10 13
Fuel clause overrecovered 8 6
Other 18 18
- ----------------------------------------------------------------
Total 478 481
- ----------------------------------------------------------------
Net deferred tax liabilities 2,470 2,460
Portion included in current assets 53 51
- ----------------------------------------------------------------
Accumulated deferred income taxes
in the Balance Sheets $ 2,523 $2,511
================================================================
Deferred investment tax credits are amortized over the life of the related
property with such amortization normally applied as a credit to reduce
depreciation in the Statements of Income. Credits amortized in this manner
amounted to $17 million in 1996, $22 million in 1995, and $25 million in 1994.
At December 31, 1996, all investment tax credits available to reduce federal
income taxes payable had been utilized.
A reconciliation of the federal statutory tax rate to the effective income
tax rate is as follows:
1996 1995 1994
-------------------------
Federal statutory rate 35% 35% 35%
State income tax, net of
federal deduction 4 4 4
Non-deductible book
depreciation 3 2 3
Difference in prior years'
deferred and current tax rate (1) (1) (1)
Other (1) - -
- -------------------------------------------------------------
Effective income tax rate 40% 40% 41%
=============================================================
28
<PAGE>
NOTES (continued)
Georgia Power Company 1996 Annual Report
Southern Company and its subsidiaries file a consolidated federal income tax
return. Under a joint consolidated income tax agreement, each subsidiary's
current and deferred tax expense is computed on a stand-alone basis. Tax
benefits from losses of the parent company are allocated to each subsidiary
based on the ratio of taxable income to total consolidated taxable income.
9. CAPITALIZATION
First Mortgage Bond Indenture & Charter Restrictions
The Company's first mortgage bond indenture contains various restrictions that
remain in effect as long as the bonds are outstanding. At December 31, 1996,
$778 million of retained earnings and paid-in capital was unrestricted for the
payment of cash dividends or any other distributions under terms of the mortgage
indenture. Supplemental indentures in connection with future first mortgage bond
issues may contain more stringent restrictions than those currently in effect.
The Company's charter limits cash dividends on common stock to the lesser of
the retained earnings balance or 75 percent of net income available for such
stock during a prior period of 12 months if the ratio of common stock equity to
total capitalization, including retained earnings, adjusted to reflect the
payment of the proposed dividend, is below 25 percent, and to 50 percent of such
net income if such ratio is less than 20 percent. At December 31, 1996, the
ratio as defined was 50.3 percent.
Preferred Securities
In December 1994, Georgia Power Capital, L.P., of which the Company is the sole
general partner, issued $100 million of 9 percent mandatorily redeemable
preferred securities. Substantially all of the assets of Georgia Power Capital
are $103 million aggregate principal amount of Georgia Power's 9 percent Junior
Subordinated Deferrable Interest Debentures due December 19, 2024. In August
1996, Georgia Power Capital Trust I (Trust I), of which the Company owns all the
common securities, issued $225 million of 7.75 percent mandatorily redeemable
preferred securities. Substantially all of the assets of Trust I are $232
million aggregate principal amount of the Company's 7.75 percent Junior
Subordinated Notes due June 30, 2036. In January 1997, Georgia Power Capital
Trust II (Trust II), of which the Company owns all the common securities, issued
$175 million of 7.60 percent mandatorily redeemable preferred securities.
Substantially all of the assets of Trust II are $180 million aggregate principal
amount of the Company's 7.60 percent Junior Subordinated Notes due December 31,
2036.
The Company considers that the mechanisms and obligations relating to the
preferred securities, taken together, constitute a full and unconditional
guarantee by the Company of Georgia Power Capital's and Georgia Power Capital
Trusts' payment obligations with respect to the preferred securities.
Georgia Power Capital, L.P., Georgia Power Capital Trust I, and Georgia
Power Capital Trust II are subsidiaries of the Company, and accordingly are
consolidated in the Company's financial statements.
Pollution Control Bonds
The Company has incurred obligations in connection with the sale by public
authorities of tax-exempt pollution control revenue bonds. The Company has
authenticated and delivered to trustees an aggregate of $1.5 billion of its
first mortgage bonds, which are pledged as security for its obligations under
pollution control revenue contracts. No interest on these first mortgage bonds
is payable unless and until a default occurs on the installment purchase or loan
agreements. An aggregate of approximately $90 million of the pollution control
revenue bonds is secured by a subordinated interest in specific property of the
Company.
Details of pollution control bonds are as follows:
Interest Rates 1996 1995
Maturity
- --------------------------------------------------------------
(in millions)
2000 4.375% $ 50 $ 50
2004-2006 5% to 6.75% 143 145
2007-2011 6.375% to 6.40% 10 20
& Variable
2016 8% - 56
2017-2021 6% to 9.375% 235 287
2022-2026 5.40% to 6.75%
& Variable 1,233 1,120
- -------------------------------------------------------------
Total pollution control bonds $ 1,671 $1,678
=============================================================
29
<PAGE>
NOTES (continued)
Georgia Power Company 1996 Annual Report
Bank Credit Arrangements
At the beginning of 1997, the Company had unused credit arrangements with banks
totaling $1.1 billion, of which $629.4 million expires at various times during
1997, $48.7 million expires at May 1, 1999, and $400 million expires at June 30,
1999.
The $400 million expiring June 30, 1999, is under revolving credit
arrangements with several banks providing the Company, Alabama Power Company,
and Southern Company up to a total credit amount of $400 million. To provide
liquidity support for commercial paper programs, $165 million, $135 million, and
$100 million are currently dedicated to the Company, Alabama Power Company, and
Southern Company, respectively. However, the allocations can be changed among
the borrowers by notifying the respective banks.
During the term of the agreements expiring in 1999, 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.
Of the Company's total $1.1 billion in unused credit arrangements, a portion
of the lines is dedicated to provide liquidity support to variable rate
pollution control bonds. The credit lines dedicated as of December 31, 1996,
were $589.7 million. In connection with all other lines of credit, the Company
has the option of paying fees or maintaining compensating balances. These
balances are not legally restricted from withdrawal.
In addition, the Company borrows under uncommitted lines of credit with
banks and through a $225 million commercial paper program that has the liquidity
support of committed bank credit arrangements. Average compensating balances
held under these committed facilities were not material in 1996.
Other Long-Term Debt
Assets acquired under capital leases are recorded in the Balance Sheets as
utility plant in service, and the related obligations are classified as
long-term debt. At December 31, 1996 and 1995, the Company had a capitalized
lease obligation for its corporate headquarters building of $87 million with an
interest rate of 8.1 percent. The lease agreement provides for payments that are
minimal in early years and escalate through the first 21 years of the lease. For
ratemaking purposes, the GPSC has treated the lease as an operating lease and
has allowed only the lease payments in cost of service. The difference between
the accrued expense and the lease payments allowed for ratemaking purposes is
being deferred as a cost to be recovered in the future as ordered by the GPSC.
At December 31, 1996, and 1995, the interest and lease amortization deferred on
the Balance Sheets are $51 million and $49 million, respectively.
Assets Subject to Lien
The Company's mortgage dated as of March 1, 1941, as amended and supplemented,
securing the first mortgage bonds issued by the Company, constitutes a direct
lien on substantially all of the Company's fixed property and franchises.
Securities Due Within One Year
The current portion of the Company's long-term debt and preferred stock is as
follows:
1996 1995
-------------------
(in millions)
First mortgage bonds $ 61 $150
Preferred stock 49 -
- ----------------------------------------------------------------
Total $ 110 $150
================================================================
The Company's first mortgage bond indenture includes an improvement fund
requirement that amounts to 1 percent of each outstanding series of bonds
authenticated under the indenture prior to January 1 of each year, other than
those issued to collateralize pollution control obligations. The requirement may
be satisfied by June 1 of each year by depositing cash, reacquiring bonds, or by
pledging additional property equal to 1 2/3 times the requirement. The 1997
requirement was met in the first quarter of the year by depositing cash with the
trustee. These funds, along with cash deposited previously with the trustee to
satisfy the 1995 and 1996 improvement fund requirements, were used to redeem
bonds.
30
<PAGE>
NOTES (continued)
Georgia Power Company 1996 Annual Report
Redemption of Securities
The Company plans to continue a program of redeeming or replacing debt and
preferred stock in cases where opportunities exist to reduce financing costs.
Issues may be repurchased in the open market or called at premiums as specified
under terms of the issue. They may also be redeemed at face value to meet
improvement fund and sinking fund requirements, to meet replacement provisions
of the mortgage, or through use of proceeds from the sale of property pledged
under the mortgage. In general, for the first five years a series is
outstanding, the Company is prohibited from redeeming for improvement fund
purposes more than 1 percent annually of the original issue amount.
10. QUARTERLY FINANCIAL DATA (UNAUDITED)
Summarized quarterly financial information for 1996 and 1995 is as follows:
Net Income
After
Dividends on
Operating Operating Preferred
Quarter Ended Revenues Income Stock
- -------------------------------------------------------------------
(in millions)
--------------------------------------------
March 1996 $ 1,029 $192 $ 114
June 1996 1,134 233 154
September 1996 1,311 339 256
December 1996 943 122 56
March 1995 $ 974 $207 $ 116
June 1995 1,075 230 149
September 1995 1,374 337 245
December 1995 982 177 99
- -------------------------------------------------------------------
Earnings in the fourth quarter of 1996, compared to the fourth quarter of
1995, declined primarily as a result of lower retail and wholesale revenues and
initiatives to reduce fossil generation materials inventory levels.
The Company's business is influenced by seasonal weather conditions.
31
<PAGE>
<TABLE>
<CAPTION>
SELECTED FINANCIAL AND OPERATING DATA
Georgia Power Company 1996 Annual Report
- -------------------------------------------------------------------------------------------------------------------------------
1996 1995 1994
- -------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Operating Revenues (in thousands) $4,416,779 $4,405,338 $4,162,403
Net Income after Dividends
on Preferred Stock (in thousands) $580,327 $608,862 $525,544
Cash Dividends on Common Stock (in thousands) $475,500 $451,500 $429,300
Return on Average Common Equity (percent) 13.73 14.43 12.84
Total Assets (in thousands) $13,071,051 $13,470,275 $13,712,658
Gross Property Additions (in thousands) $428,220 $480,449 $638,426
- -------------------------------------------------------------------------------------------------------------------------------
Capitalization (in thousands):
Common stock equity $4,154,281 $4,299,012 $4,141,554
Preferred stock 464,611 692,787 692,787
Preferred stock subject to mandatory redemption - - -
Company obligated mandatorily redeemable preferred securities 325,000 100,000 100,000
Long-term debt 3,200,419 3,315,460 3,757,823
- -------------------------------------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) $8,144,311 $8,407,259 $8,692,164
===============================================================================================================================
Capitalization Ratios (percent):
Common stock equity 51.0 51.1 47.6
Preferred stock 5.7 8.2 8.0
Company obligated mandatorily redeemable preferred securities 4.0 1.2 1.2
Long-term debt 39.3 39.5 43.2
- -------------------------------------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) 100.0 100.0 100.0
===============================================================================================================================
First Mortgage Bonds (in thousands):
Issued 10,000 75,000 -
Retired 210,860 505,789 133,559
Preferred Stock (in thousands):
Issued - - -
Retired 179,148 - -
Company Obligated Mandatorily Redeemable
Preferred Securities (in thousands):
Issued 225,000 - 100,000
- -------------------------------------------------------------------------------------------------------------------------------
Security Ratings:
First Mortgage Bonds -
Moody's A1 A1 A2
Standard and Poor's A+ A+ A
Duff & Phelps AA- AA- A+
Preferred Stock -
Moody's a2 a2 a3
Standard and Poor's A A A-
Duff & Phelps A+ A A-
- -------------------------------------------------------------------------------------------------------------------------------
Customers (year-end):
Residential 1,531,453 1,500,024 1,466,382
Commercial 205,087 198,624 193,648
Industrial 10,424 10,796 10,976
Other 2,645 2,568 2,426
- -------------------------------------------------------------------------------------------------------------------------------
Total 1,749,609 1,712,012 1,673,432
===============================================================================================================================
Employees (year-end) 10,346 11,061 11,765
</TABLE>
32
<PAGE>
<TABLE>
<CAPTION>
SELECTED FINANCIAL AND OPERATING DATA
Georgia Power Company 1996 Annual Report
- ------------------------------------------------------------------------------------------------------------------------
1993 1992 1991
- ------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Operating Revenues (in thousands) $4,451,181 $4,297,436 $4,301,428
Net Income after Dividends
on Preferred Stock (in thousands) $569,853 $520,538 $474,855
Cash Dividends on Common Stock (in thousands) $402,400 $384,000 $375,200
Return on Average Common Equity (percent) 14.37 13.60 12.76
Total Assets (in thousands) $13,736,110 $10,964,442 $10,842,538
Gross Property Additions (in thousands) $674,432 $508,444 $548,051
- ------------------------------------------------------------------------------------------------------------------------
Capitalization (in thousands):
Common stock equity $4,045,458 $3,888,237 $3,766,551
Preferred stock 692,787 692,792 607,796
Preferred stock subject to mandatory redemption - 6,250 118,750
Company obligated mandatorily redeemable preferred securities - - -
Long-term debt 4,031,387 4,131,016 4,553,189
- ------------------------------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) $8,769,632 $8,718,295 $9,046,286
========================================================================================================================
Capitalization Ratios (percent):
Common stock equity 46.1 44.6 41.7
Preferred stock 7.9 8.0 8.0
Company obligated mandatorily redeemable preferred securities - - -
Long-term debt 46.0 47.4 50.3
- ------------------------------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) 100.0 100.0 100.0
========================================================================================================================
First Mortgage Bonds (in thousands):
Issued 1,135,000 975,000 -
Retired 1,337,822 1,381,300 598,384
Preferred Stock (in thousands):
Issued 175,000 195,000 100,000
Retired 245,005 165,004 100,000
Company Obligated Mandatorily Redeemable
Preferred Securities (in thousands):
Issued - - -
- ------------------------------------------------------------------------------------------------------------------------
Security Ratings:
First Mortgage Bonds -
Moody's A3 A3 Baa1
Standard and Poor's A- A- BBB+
Duff & Phelps A+ A- BBB+
Preferred Stock -
Moody's baa1 baa1 baa1
Standard and Poor's BBB+ BBB+ BBB
Duff & Phelps A- BBB BBB-
- ------------------------------------------------------------------------------------------------------------------------
Customers (year-end):
Residential 1,441,972 1,421,175 1,397,682
Commercial 188,820 183,784 179,933
Industrial 11,217 11,479 11,946
Other 2,322 2,269 2,190
- ------------------------------------------------------------------------------------------------------------------------
Total 1,644,331 1,618,707 1,591,751
========================================================================================================================
Employees (year-end) 12,528 12,600 13,700
</TABLE>
33A
<PAGE>
<TABLE>
<CAPTION>
SELECTED FINANCIAL AND OPERATING DATA
Georgia Power Company 1996 Annual Report
- -----------------------------------------------------------------------------------------------------------------------------
1990 1989 1988
- -----------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Operating Revenues (in thousands) $4,445,809 $4,145,240 $3,897,479
Net Income after Dividends
on Preferred Stock (in thousands) $208,066 $449,099 $479,532
Cash Dividends on Common Stock (in thousands) $389,600 $394,500 $386,600
Return on Average Common Equity (percent) 5.52 11.72 13.06
Total Assets (in thousands) $11,176,619 $11,372,346 $11,130,539
Gross Property Additions (in thousands) $558,727 $727,631 $929,019
- -----------------------------------------------------------------------------------------------------------------------------
Capitalization (in thousands):
Common stock equity $3,673,913 $3,860,657 $3,806,070
Preferred stock 607,796 607,844 657,844
Preferred stock subject to mandatory redemption 125,000 155,000 162,500
Company obligated mandatorily redeemable preferred securities - - -
Long-term debt 5,000,225 5,054,001 4,861,378
- -----------------------------------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) $9,406,934 $9,677,502 $9,487,792
=============================================================================================================================
Capitalization Ratios (percent):
Common stock equity 39.1 39.9 40.1
Preferred stock 7.8 7.9 8.6
Company obligated mandatorily redeemable preferred securities - - -
Long-term debt 53.1 52.2 51.3
- -----------------------------------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) 100.0 100.0 100.0
=============================================================================================================================
First Mortgage Bonds (in thousands):
Issued 300,000 250,000 150,000
Retired 91,117 91,516 206,677
Preferred Stock (in thousands):
Issued - - -
Retired 83,750 7,500 3,750
Company Obligated Mandatorily Redeemable
Preferred Securities (in thousands):
Issued - - -
- -----------------------------------------------------------------------------------------------------------------------------
Security Ratings:
First Mortgage Bonds -
Moody's Baa1 Baa2 Baa2
Standard and Poor's BBB+ BBB+ BBB
Duff & Phelps BBB BBB 9
Preferred Stock -
Moody's baa1 baa2 baa2
Standard and Poor's BBB BBB BBB-
Duff & Phelps BBB- BBB- 10
- -----------------------------------------------------------------------------------------------------------------------------
Customers (year-end):
Residential 1,378,888 1,355,211 1,329,173
Commercial 178,391 177,814 174,147
Industrial 12,115 12,311 12,353
Other 2,114 2,050 1,993
- -----------------------------------------------------------------------------------------------------------------------------
Total 1,571,508 1,547,386 1,517,666
=============================================================================================================================
Employees (year-end) 13,746 13,900 15,110
</TABLE>
33B
<PAGE>
<TABLE>
<CAPTION>
SELECTED FINANCIAL AND OPERATING DATA
Georgia Power Company 1996 Annual Report
- ------------------------------------------------------------------------------------------------------
1987 1986
- ------------------------------------------------------------------------------------------------------
<S> <C> <C>
Operating Revenues (in thousands) $3,786,485 $3,561,603
Net Income after Dividends
on Preferred Stock (in thousands) $240,057 $535,003
Cash Dividends on Common Stock (in thousands) $377,800 $325,500
Return on Average Common Equity (percent) 6.85 16.51
Total Assets (in thousands) $11,197,494 $10,465,063
Gross Property Additions (in thousands) $1,034,059 $1,598,309
- ------------------------------------------------------------------------------------------------------
Capitalization (in thousands):
Common stock equity $3,538,182 $3,469,201
Preferred stock 657,844 732,844
Preferred stock subject to mandatory redemption 166,250 112,500
Company obligated mandatorily redeemable preferred securities - -
Long-term debt 4,825,760 4,464,857
- ------------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) $9,188,036 $8,779,402
======================================================================================================
Capitalization Ratios (percent):
Common stock equity 38.5 39.5
Preferred stock 9.0 9.6
Company obligated mandatorily redeemable preferred securities - -
Long-term debt 52.5 50.9
- ------------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) 100.0 100.0
======================================================================================================
First Mortgage Bonds (in thousands):
Issued 500,000 500,000
Retired 217,949 377,538
Preferred Stock (in thousands):
Issued 125,000 100,000
Retired 150,000 7,500
Company Obligated Mandatorily Redeemable
Preferred Securities (in thousands):
Issued - -
- ------------------------------------------------------------------------------------------------------
Security Ratings:
First Mortgage Bonds -
Moody's Baa2 Baa1
Standard and Poor's BBB BBB+
Duff & Phelps 9 9
Preferred Stock -
Moody's baa2 baa1
Standard and Poor's BBB- BBB
Duff & Phelps 10 10
- ------------------------------------------------------------------------------------------------------
Customers (year-end):
Residential 1,303,721 1,268,983
Commercial 169,014 162,258
Industrial 12,307 12,315
Other 1,858 1,816
- ------------------------------------------------------------------------------------------------------
Total 1,486,900 1,445,372
======================================================================================================
Employees (year-end) 14,924 14,773
</TABLE>
33C
<PAGE>
<TABLE>
<CAPTION>
SELECTED FINANCIAL AND OPERATING DATA (continued)
Georgia Power Company 1996 Annual Report
- -----------------------------------------------------------------------------------------------------------------------
1996 1995 1994
- -----------------------------------------------------------------------------------------------------------------------
Operating Revenues (in thousands):
<S> <C> <C> <C>
Residential $1,371,033 $1,337,060 $1,180,358
Commercial 1,486,586 1,449,108 1,367,315
Industrial 1,118,633 1,141,766 1,100,995
Other 47,060 44,255 42,983
- -----------------------------------------------------------------------------------------------------------------------
Total retail 4,023,312 3,972,189 3,691,651
Sales for resale - non-affiliates 281,580 290,302 351,591
Sales for resale - affiliates 35,886 76,906 60,899
- -----------------------------------------------------------------------------------------------------------------------
Total revenues from sales of electricity 4,340,778 4,339,397 4,104,141
Other revenues 76,001 65,941 58,262
- -----------------------------------------------------------------------------------------------------------------------
Total $4,416,779 $4,405,338 $4,162,403
=======================================================================================================================
Kilowatt-Hour Sales (in thousands):
Residential 17,826,451 17,307,399 15,680,709
Commercial 20,823,073 19,844,999 18,738,461
Industrial 26,191,831 25,286,340 24,337,632
Other 536,057 493,720 484,009
- -----------------------------------------------------------------------------------------------------------------------
Total retail 65,377,412 62,932,458 59,240,811
Sales for resale - non-affiliates 7,868,342 6,591,841 7,968,475
Sales for resale - affiliates 1,180,207 2,738,947 3,056,050
- -----------------------------------------------------------------------------------------------------------------------
Total 74,425,961 72,263,246 70,265,336
=======================================================================================================================
Average Revenue Per Kilowatt-Hour (cents):
Residential 7.69 7.73 7.53
Commercial 7.14 7.30 7.30
Industrial 4.27 4.52 4.52
Total retail 6.15 6.31 6.23
Sales for resale 3.51 3.94 3.74
Total sales 5.83 6.00 5.84
Residential Average Annual Kilowatt-Hour Use Per Customer 11,763 11,654 10,766
Residential Average Annual Revenue Per Customer $904.70 $900.28 $810.39
Plant Nameplate Capacity Ratings (year-end) (megawatts) 14,367 14,344 13,943
Maximum Peak-Hour Demand (megawatts) (Note A):
Winter 10,410 9,819 10,509
Summer 12,914 12,828 11,758
Annual Load Factor (percent) 62.2 59.6 63.0
Plant Availability (percent):
Fossil-steam 85.2 85.8 83.1
Nuclear 89.3 91.8 88.4
- -----------------------------------------------------------------------------------------------------------------------
Source of Energy Supply (percent):
Coal 60.4 63.0 61.3
Nuclear 18.2 19.3 18.0
Hydro 2.2 2.5 2.6
Oil and gas 0.5 0.6 0.1
Purchased power -
From non-affiliates 5.6 7.7 9.7
From affiliates 13.1 6.9 8.3
- -----------------------------------------------------------------------------------------------------------------------
Total 100.0 100.0 100.0
=======================================================================================================================
Total Fuel Economy Data:
BTU per net kilowatt-hour generated 10,468 10,039 9,915
Cost of fuel per million BTU (cents) 128.72 143.85 145.33
Average cost of fuel per net kilowatt-hour generated (cents) 1.35 1.44 1.44
=======================================================================================================================
Note A: As of 9/1/91, Georgia Power Company's sales to Oglethorpe Power Company are not included in Peak-Hour Demand.
* Less than one-tenth of one percent.
</TABLE>
34
<PAGE>
<TABLE>
<CAPTION>
SELECTED FINANCIAL AND OPERATING DATA (continued)
Georgia Power Company 1996 Annual Report
- ------------------------------------------------------------------------------------------------------------------------------
1993 1992 1991
- ------------------------------------------------------------------------------------------------------------------------------
Operating Revenues (in thousands):
<S> <C> <C> <C>
Residential $1,291,035 $1,128,396 $1,111,358
Commercial 1,354,130 1,285,681 1,243,067
Industrial 1,113,067 1,083,856 1,057,702
Other 41,399 39,504 37,861
- ------------------------------------------------------------------------------------------------------------------------------
Total retail 3,799,631 3,537,437 3,449,988
Sales for resale - non-affiliates 534,370 640,308 736,643
Sales for resale - affiliates 61,668 67,835 65,586
- ------------------------------------------------------------------------------------------------------------------------------
Total revenues from sales of electricity 4,395,669 4,245,580 4,252,217
Other revenues 55,512 51,856 49,211
- ------------------------------------------------------------------------------------------------------------------------------
Total $4,451,181 $4,297,436 $4,301,428
==============================================================================================================================
Kilowatt-Hour Sales (in thousands):
Residential 16,649,859 14,939,172 14,815,089
Commercial 18,278,508 17,260,614 16,885,833
Industrial 23,635,363 22,978,312 22,298,062
Other 460,801 436,144 429,016
- ------------------------------------------------------------------------------------------------------------------------------
Total retail 59,024,531 55,614,242 54,428,000
Sales for resale - non-affiliates 14,307,030 15,870,222 18,719,924
Sales for resale - affiliates 3,027,733 3,320,060 3,885,892
- ------------------------------------------------------------------------------------------------------------------------------
Total 76,359,294 74,804,524 77,033,816
==============================================================================================================================
Average Revenue Per Kilowatt-Hour (cents):
Residential 7.75 7.55 7.50
Commercial 7.41 7.45 7.36
Industrial 4.71 4.72 4.74
Total retail 6.44 6.36 6.34
Sales for resale 3.44 3.69 3.55
Total sales 5.76 5.68 5.52
Residential Average Annual Kilowatt-Hour Use Per Customer 11,630 10,603 10,675
Residential Average Annual Revenue Per Customer $901.79 $800.88 $800.78
Plant Nameplate Capacity Ratings (year-end) (megawatts) 13,759 14,076 14,076
Maximum Peak-Hour Demand (megawatts) (Note A):
Winter 9,067 8,938 10,001
Summer 12,573 11,448 13,090
Annual Load Factor (percent) 58.5 60.5 55.2
Plant Availability (percent):
Fossil-steam 85.9 86.6 93.3
Nuclear 85.5 87.7 81.6
- ------------------------------------------------------------------------------------------------------------------------------
Source of Energy Supply (percent):
Coal 62.1 61.4 63.6
Nuclear 16.2 17.0 15.3
Hydro 2.3 2.5 2.3
Oil and gas 0.2 * *
Purchased power -
From non-affiliates 10.2 12.2 10.3
From affiliates 9.0 6.9 8.5
- ------------------------------------------------------------------------------------------------------------------------------
Total 100.0 100.0 100.0
==============================================================================================================================
Total Fuel Economy Data:
BTU per net kilowatt-hour generated 9,912 9,900 9,960
Cost of fuel per million BTU (cents) 153.62 153.08 157.97
Average cost of fuel per net kilowatt-hour generated (cents) 1.52 1.52 1.57
==============================================================================================================================
Note A: As of 9/1/91, Georgia Power Company's sales to Oglethorpe Power Company are not included in Peak-Hour Demand.
* Less than one-tenth of one percent.
</TABLE>
35A
<PAGE>
<TABLE>
<CAPTION>
SELECTED FINANCIAL AND OPERATING DATA (continued)
Georgia Power Company 1996 Annual Report
- ------------------------------------------------------------------------------------------------------------------------------
1990 1989 1988
- ------------------------------------------------------------------------------------------------------------------------------
Operating Revenues (in thousands):
<S> <C> <C> <C>
Residential $1,109,165 $1,022,781 $979,047
Commercial 1,218,441 1,143,727 1,054,995
Industrial 1,061,830 1,006,416 983,822
Other 36,773 34,775 31,743
- ------------------------------------------------------------------------------------------------------------------------------
Total retail 3,426,209 3,207,699 3,049,607
Sales for resale - non-affiliates 784,086 760,809 707,076
Sales for resale - affiliates 168,251 150,394 86,751
- ------------------------------------------------------------------------------------------------------------------------------
Total revenues from sales of electricity 4,378,546 4,118,902 3,843,434
Other revenues 67,263 26,338 54,045
- ------------------------------------------------------------------------------------------------------------------------------
Total $4,445,809 $4,145,240 $3,897,479
==============================================================================================================================
Kilowatt-Hour Sales (in thousands):
Residential 14,771,648 14,134,195 13,800,038
Commercial 16,627,128 15,843,181 14,790,561
Industrial 22,126,604 21,801,404 21,412,845
Other 428,459 414,107 397,669
- ------------------------------------------------------------------------------------------------------------------------------
Total retail 53,953,839 52,192,887 50,401,113
Sales for resale - non-affiliates 20,158,681 20,479,412 18,544,705
Sales for resale - affiliates 8,272,528 7,489,948 3,327,814
- ------------------------------------------------------------------------------------------------------------------------------
Total 82,385,048 80,162,247 72,273,632
==============================================================================================================================
Average Revenue Per Kilowatt-Hour (cents):
Residential 7.51 7.24 7.09
Commercial 7.33 7.22 7.13
Industrial 4.80 4.62 4.59
Total retail 6.35 6.15 6.05
Sales for resale 3.35 3.26 3.63
Total sales 5.31 5.14 5.32
Residential Average Annual Kilowatt-Hour Use Per Customer 10,795 10,530 10,484
Residential Average Annual Revenue Per Customer $810.56 $761.96 $743.82
Plant Nameplate Capacity Ratings (year-end) (megawatts) 14,366 14,366 13,018
Maximum Peak-Hour Demand (megawatts) (Note A):
Winter 8,977 10,101 9,866
Summer 13,196 12,735 12,295
Annual Load Factor (percent) 55.5 56.3 59.1
Plant Availability (percent):
Fossil-steam 92.5 93.0 94.5
Nuclear 81.3 89.2 69.4
- ------------------------------------------------------------------------------------------------------------------------------
Source of Energy Supply (percent):
Coal 65.1 64.0 72.0
Nuclear 13.7 14.1 9.6
Hydro 2.2 2.1 1.2
Oil and gas 0.1 0.1 0.1
Purchased power -
From non-affiliates 11.0 10.2 8.2
From affiliates 7.9 9.5 8.9
- ------------------------------------------------------------------------------------------------------------------------------
Total 100.0 100.0 100.0
==============================================================================================================================
Total Fuel Economy Data:
BTU per net kilowatt-hour generated 9,939 10,020 9,969
Cost of fuel per million BTU (cents) 166.22 164.27 166.28
Average cost of fuel per net kilowatt-hour generated (cents) 1.65 1.65 1.66
==============================================================================================================================
Note A: As of 9/1/91, Georgia Power Company's sales to Oglethorpe Power Company are not included in Peak-Hour Demand.
* Less than one-tenth of one percent.
</TABLE>
35B
<PAGE>
<TABLE>
<CAPTION>
SELECTED FINANCIAL AND OPERATING DATA (continued)
Georgia Power Company 1996 Annual Report
- -------------------------------------------------------------------------------------------------------------
1987 1986
- -------------------------------------------------------------------------------------------------------------
Operating Revenues (in thousands):
<S> <C> <C>
Residential $904,218 $874,231
Commercial 915,540 854,755
Industrial 911,933 897,646
Other 29,350 27,948
- -------------------------------------------------------------------------------------------------------------
Total retail 2,761,041 2,654,580
Sales for resale - non-affiliates 822,696 780,049
Sales for resale - affiliates 159,998 91,753
- -------------------------------------------------------------------------------------------------------------
Total revenues from sales of electricity 3,743,735 3,526,382
Other revenues 42,750 35,221
- -------------------------------------------------------------------------------------------------------------
Total $3,786,485 $3,561,603
=============================================================================================================
Kilowatt-Hour Sales (in thousands):
Residential 13,675,730 13,234,248
Commercial 13,799,379 12,945,926
Industrial 20,884,454 20,339,235
Other 385,514 381,917
- -------------------------------------------------------------------------------------------------------------
Total retail 48,745,077 46,901,326
Sales for resale - non-affiliates 20,910,185 18,198,186
Sales for resale - affiliates 6,032,889 3,160,242
- -------------------------------------------------------------------------------------------------------------
Total 75,688,151 68,259,754
=============================================================================================================
Average Revenue Per Kilowatt-Hour (cents):
Residential 6.61 6.61
Commercial 6.63 6.60
Industrial 4.37 4.41
Total retail 5.66 5.66
Sales for resale 3.65 4.08
Total sales 4.95 5.17
Residential Average Annual Kilowatt-Hour Use Per Customer 10,623 10,577
Residential Average Annual Revenue Per Customer $702.36 $698.72
Plant Nameplate Capacity Ratings (year-end) (megawatts) 13,018 11,875
Maximum Peak-Hour Demand (megawatts) (Note A):
Winter 9,446 10,551
Summer 12,390 11,910
Annual Load Factor (percent) 56.1 57.5
Plant Availability (percent):
Fossil-steam 92.7 91.2
Nuclear 85.4 64.7
- ---------------------------------------------------------------------------------------------------------------
Source of Energy Supply (percent):
Coal 70.9 74.6
Nuclear 9.1 5.0
Hydro 1.7 1.2
Oil and gas 0.1 0.6
Purchased power -
From non-affiliates 8.5 8.9
From affiliates 9.7 9.7
- --------------------------------------------------------------------------------------------------------------
Total 100.0 100.0
==============================================================================================================
Total Fuel Economy Data:
BTU per net kilowatt-hour generated 9,932 10,016
Cost of fuel per million BTU (cents) 168.81 175.81
Average cost of fuel per net kilowatt-hour generated (cents) 1.68 1.76
==============================================================================================================
Note A: As of 9/1/91, Georgia Power Company's sales to Oglethorpe Power Company are not included in Peak-Hour Demand.
* Less than one-tenth of one percent.
</TABLE>
35C
