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 21, 1996
------------------------
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, 1995.
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
/s/ Wayne Boston
By Wayne Boston
Assistant Secretary
Date: March 1, 1996
EXHIBIT 23
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the incorporation
of our report dated February 21, 1996 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 28, 1996
<PAGE>
<TABLE> <S> <C>
<ARTICLE> UT
<LEGEND>
This legend contains summary financial information extracted from the financial
statements filed as Exhibit 99 and is qualified in its entirety by reference to
such financial statements.
</LEGEND>
<CIK> 0000041091
<NAME> GEORGIA POWER COMPANY
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1995
<PERIOD-END> DEC-31-1995
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 10,483,039
<OTHER-PROPERTY-AND-INVEST> 239,888
<TOTAL-CURRENT-ASSETS> 1,136,376
<TOTAL-DEFERRED-CHARGES> 1,610,972
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 13,470,275
<COMMON> 344,250
<CAPITAL-SURPLUS-PAID-IN> 2,384,857
<RETAINED-EARNINGS> 1,569,905
<TOTAL-COMMON-STOCKHOLDERS-EQ> 4,299,012
100,000
692,787
<LONG-TERM-DEBT-NET> 3,378,506
<SHORT-TERM-NOTES> 178,000
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 222,330
<LONG-TERM-DEBT-CURRENT-PORT> (150,110)
0
<CAPITAL-LEASE-OBLIGATIONS> 87,400
<LEASES-CURRENT> (336)
<OTHER-ITEMS-CAPITAL-AND-LIAB> 4,662,686
<TOT-CAPITALIZATION-AND-LIAB> 13,470,275
<GROSS-OPERATING-REVENUE> 4,405,338
<INCOME-TAX-EXPENSE> 449,204
<OTHER-OPERATING-EXPENSES> 3,005,255
<TOTAL-OPERATING-EXPENSES> 3,454,459
<OPERATING-INCOME-LOSS> 950,879
<OTHER-INCOME-NET> 6,358
<INCOME-BEFORE-INTEREST-EXPEN> 957,237
<TOTAL-INTEREST-EXPENSE> 300,223
<NET-INCOME> 657,014
48,152
<EARNINGS-AVAILABLE-FOR-COMM> 608,862
<COMMON-STOCK-DIVIDENDS> 451,500
<TOTAL-INTEREST-ON-BONDS> 228,539
<CASH-FLOW-OPERATIONS> 1,418,023
<EPS-PRIMARY> 0
<EPS-DILUTED> 0
</TABLE>
Exhibit 99
MANAGEMENT'S REPORT
Georgia Power Company 1995 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 21, 1996
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 wholly owned subsidiary of
The Southern Company) as of December 31, 1995 and 1994, 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, 1995. These financial
statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements (pages 11-32) referred to above
present fairly, in all material respects, the financial position of Georgia
Power Company as of December 31, 1995 and 1994, and the results of its
operations and its cash flows for the periods stated, in conformity with
generally accepted accounting principles.
/s/ Arthur Andersen LLP
Atlanta, Georgia
February 21, 1996
2
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL
CONDITION
Georgia Power Company 1995 Annual Report
RESULTS OF OPERATIONS
Earnings
Georgia Power Company's 1995 earnings totaled $609 million, representing an $83
million (15.9 percent) increase 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 the 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. Earnings
for 1994 declined from the prior year not only because of the work force
reduction charge but also because of lower retail energy sales due to mild
weather. The summer of 1993 was exceptionally hot in comparison.
Revenues
The following table summarizes the factors impacting operating revenues for the
1993-1995 period:
Increase (Decrease)
From Prior Year
-----------------------------------
1995 1994 1993
-----------------------------------
Retail - (in millions)
Sales growth $110 $ 67 $ 45
Weather 69 (128) 126
Fuel cost recovery 66 (35) 76
Demand-side programs 36 (12) 15
-----------------------------------------------------------------
Total retail 281 (108) 262
- ------------------------------------------------------------------
Sales for resale -
Non-affiliates (61) (183) (106)
Affiliates 16 (1) (6)
- ------------------------------------------------------------------
Total sales for resale (45) (184) (112)
- ------------------------------------------------------------------
Other operating revenues 7 3 4
- ------------------------------------------------------------------
Total operating revenues $243 ($289) $154
- ------------------------------------------------------------------
Percent change 5.8% (6.5)% 3.6%
- ------------------------------------------------------------------
Retail revenues of $4.0 billion in 1995 increased $281 million (7.6 percent)
over the prior year, compared with a decrease of $108 million (2.8 percent) in
1994. Sales growth, reflecting continued expansion of Georgia's economy, and the
hot summer of 1995, compared to the milder-than-normal weather during the summer
of 1994, were the primary reasons for the increase in retail revenues. Retail
revenues were down in 1994 from the prior year primarily due to hot summer
weather in 1993.
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 1995 and
1994. 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:
1995 1994 1993
-------------------------------
(in millions)
Capacity $53 $ 84 $152
Energy 45 82 113
- --------------------------------------------------------------
Total $98 $166 $265
==============================================================
Contractual unit power sales to Florida utilities for 1995 and 1994 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 155 megawatts and 427
megawatts in 1995 and 1994, respectively. In 1996, the contracted capacity will
decline another 75 megawatts.
Sales to municipalities and cooperatives in Georgia increased in 1995 due to
higher summer demand resulting from the hot weather; however, such sales
decreased in 1994 as these customers retained more of their own generation at
jointly owned facilities, and as a result of a new agreement with territorial
wholesale customers.
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.
3
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 1995 Annual Report
Kilowatt-hour (KWH) sales for 1995 and the percent change by year were as
follows:
Percent Change
----------------------------
1995
KWH 1995 1994 1993
----------------------------------------
(in billions)
Residential 17.3 10.4% (5.8)% 11.5%
Commercial 19.8 5.9 2.5 5.9
Industrial 25.3 3.9 3.0 2.9
Other 0.5 2.0 5.0 5.7
-------
Total retail 62.9 6.2 0.4 6.1
-------
Sales for resale -
Non-affiliates 6.6 (17.3) (44.3) (9.8)
Affiliates 2.8 (10.4) 0.9 (8.8)
-------
Total sales for resale 9.4 (15.4) (36.4) (9.7)
-------
Total sales 72.3 2.8 (8.0) 2.1
=======
- -----------------------------------------------------------------
Residential, commercial and industrial energy sales growth in 1995 reflected
continued expansion of Georgia's economy, hot summer weather, and an increase in
customers served. The 1994 sales decline in the residential class was primarily
the result of milder-than-normal summer weather in 1994. However in 1994,
industrial and commercial sales were positively impacted by continued
improvement in economic conditions. Assuming normal weather, sales to retail
customers are projected to grow approximately 2 percent annually on average
during 1996 through 1998.
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:
1995 1994 1993
---------------------------
Total generation
(billions of kilowatt-hours) 64 62 64
Sources of generation
(percent) --
Coal 73.7 74.8 76.9
Nuclear 22.6 21.9 20.0
Hydro 3.0 3.1 2.8
Oil and gas 0.7 0.2 0.3
Average cost of fuel per net
kilowatt-hour generated
(cents) --
Coal 1.67 1.67 1.75
Nuclear 0.60 0.63 0.58
Oil and gas * * *
Total 1.44 1.44 1.52
- ---------------------------------------------------------------
* Not meaningful because of minimal generation from
fuel source.
Fuel expense increased 3.5 percent in 1995 because of higher generation
which stemmed from greater demand. Fuel expense decreased 8.5 percent in 1994
due to lower fuel costs, lower generation, and the displacement of coal-fired
generation with lower cost nuclear generation.
Purchased power expense has decreased significantly since 1993, reflecting
declining contractual capacity purchases from the co-owners of Plant Vogtle.
Purchased power expense decreased $36 million in 1995 and $156 million in 1994.
The declines in 1995 and 1994 also resulted from decreased purchases from
affiliated companies, and in 1994 from decreased energy purchases from
territorial wholesale customers. The declines in Plant Vogtle contractual
capacity purchases did not have a significant impact on earnings in 1995 and
1994 since these costs are being levelized over six years under the terms of the
1991 Georgia Public Service Commission
4
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 1995 Annual Report
(GPSC) retail rate order. The levelization is reflected in the amortization of
deferred Plant Vogtle costs in the Statements of Income. See Note 3 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 $11 million in 1995 and
$82 million in 1994.
Other operation and maintenance (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. Other O&M expenses decreased 4.5 percent
in 1994 primarily due to environmental remediation costs at various sites of $32
million in 1993 compared to $8 million in 1994; recognition in 1993 of the
one-time cost of an automotive fleet reduction program; and lower maintenance
and pension costs during 1994.
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 5.2 percent in 1995 and 1.0 percent
in 1994, reflecting primarily higher ad valorem taxes and in 1995, higher
franchise taxes paid to municipalities as a result of increased sales.
Income tax expense fluctuates directly with earnings.
Other income (expense), net decreased in 1995 primarily due to an increase
in charitable contributions.
Interest expense decreased $51 million (14.6 percent) and $61 million (14.7
percent) in 1995 and 1994, respectively, due primarily to refinancing of
long-term debt. The Company refinanced $505 million and $510 million of
securities in 1995 and 1994, respectively. The Company also retired $264 million
of long-term debt with the proceeds from the 1995 and 1994 Plant Scherer Unit 4
sales. Other interest charges in 1993 include interest related to the settlement
of an Internal Revenue Service (IRS) audit.
The settlement had no effect on 1993 net income.
The Company has deferred certain expenses and recorded a deferred return
related to Plant Vogtle under phase-in plans. See Note 3 to the financial
statements under "Plant Vogtle Phase-In Plans" for information regarding the
deferral and subsequent amortization of costs related to Plant Vogtle.
Effects of Inflation
The Company is subject to rate regulation and income tax laws that are based on
the recovery of historical costs. Therefore, inflation creates an economic loss
because the Company is recovering its costs of investments in dollars that have
less purchasing power. While the inflation rate has been relatively low in
recent years, it continues to have an adverse effect on the Company because of
the large investment in long-lived utility plant. Conventional accounting for
historical cost does not recognize either this economic loss or the partially
offsetting gain that arises through financing facilities with fixed-money
obligations such as long-term debt and preferred stock. Any recognition of
inflation by regulatory authorities is reflected in the rate of return allowed.
Future Earnings Potential
The results of operations for the past three years are not necessarily
indicative of future earnings. The level of future earnings depends on numerous
factors including energy sales and regulatory matters.
Beginning January 1, 1996, the Company will operate under a three-year
retail rate plan. The plan, which was approved by the GPSC on February 16, 1996,
concludes a GPSC review of the Company's earnings and addresses an alternative
rate plan proposed by the Company. Under the plan, the Company's earnings will
be 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
5
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 1995 Annual Report
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 plan's three-year operation, including $14 million annually of accelerated
depreciation of electric plant. During the plan'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 plan, 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 rate plan or adopt a different one.
Growth in energy sales is subject to a number of factors which traditionally
have included: changes in contracts with neighboring utilities; energy
conservation practiced by customers; the elasticity of demand; weather;
competition; and the rate of economic growth in the Company's service area.
Assuming normal weather, retail sales growth is projected to be approximately 2
percent annually on average during 1996 through 1998.
The addition of four combustion turbine generating units and the Rocky
Mountain pumped storage hydroelectric plant in 1995 and the scheduled addition
of one jointly owned combustion turbine unit in 1996, will increase related O&M
and depreciation expenses. In addition, the Company has entered into a four-year
purchase power agreement to meet peaking needs whereby the Company will purchase
400 megawatts of capacity beginning in 1996 and declining to 200 megawatts of
capacity in 1998. Capacity payments are projected to be $6 million in 1996 and
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.
Work force reduction programs implemented in 1994 and 1995 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 is approximately $190 million.
See Note 3 to the financial statements for information regarding proceedings
with respect to the Company's recovery of demand-side conservation program
costs.
During 1995, the Company sold its remaining interest in Unit 4 of Plant
Scherer to two Florida utilities. This transaction coincided with scheduled
reductions in capacity revenues from Florida utilities under contractual unit
power sales contracts of approximately $22 million in 1995 and an additional $7
million in 1996. See Notes 6 and 7 to the financial statements for additional
information.
During 1994 and 1995, Oglethorpe Power Corporation (OPC) gave the Company
notice of its intent to decrease its purchases of capacity under a power supply
agreement by 250 megawatts in September 1996 and an additional 250 megawatts in
September 1997. As a result, the Company's capacity revenues from OPC will
decline approximately $8 million in 1996, an additional $25 million in 1997, and
an additional $18 million in 1998.
OPC and the Municipal Electric Authority of Georgia (MEAG) have filed joint
complaints in two separate venues seeking to recover from the Company
approximately $16.5 million in alleged overcharges, plus approximately $6.3
million in interest. See Note 3 to the financial statements under "Wholesale
Litigation" for further discussion of this matter.
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
6
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 1995 Annual Report
Act and other environmental issues are discussed later under "Environmental
Issues."
The Energy Policy Act of 1992 (Energy Act) is beginning to have 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 posturing 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. Although
the Energy Act does not require transmission access to retail customers, retail
wheeling initiatives are rapidly evolving and becoming very prominent issues in
several states. New federal legislation is being discussed and legislation
allowing customer choice has been introduced in Georgia. In order to address
these initiatives, numerous questions must be resolved with the most complex
ones relating to transmission pricing and recovery of stranded investments. As
the initiatives become a reality, the structure of the utility industry could
radically change. Therefore, unless the Company remains a low-cost producer and
provides quality service, the Company's retail energy sales growth could be
limited, and this could significantly erode earnings. Conversely, being the
low-cost producer could provide significant opportunities to increase market
share and profitability.
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. In addition, the bulk
power market has become very competitive as utilities, IPPs and cogenerators
seek to supply future capacity needs. Competition can create new business
opportunities, but it increases risk and has the potential to adversely affect
earnings.
The 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 -- 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 increase.
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.
New Accounting Standards
The FASB has issued Statement No. 121, Accounting for the Impairment of
Long-Lived Assets and Long-Lived Assets to Be Disposed Of. This statement
requires that long-lived assets be reviewed for impairment whenever events or
changes in circumstances indicate that the carrying amount of an asset may not
be recoverable. This statement also imposes stricter criteria for regulatory
assets by requiring that such assets be probable of future recovery at each
balance sheet date. The Company adopted this standard January 1, 1996 with no
material effect on the financial statements. However, this conclusion may change
in the future as competitive factors influence wholesale and retail pricing in
this industry.
7
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 1995 Annual Report
FINANCIAL CONDITION
Overview
The principal changes in the Company's financial condition in 1995 were gross
utility plant additions of $480 million, which included the commercial operation
of four combustion turbine units (cumulatively, 320 megawatts of capacity) and
all three units of the Rocky Mountain pumped storage hydroelectric plant (the
Company's ownership interest is approximately 70 megawatts of capacity per
unit). In addition, the cost of capital was lowered through the refinancing or
retirement of $1.0 billion of long-term debt.
The funds needed for gross property additions are currently provided from
operations. The Statements of Cash Flows provide additional details.
Financing Activities
In 1995, the Company continued to lower its financing costs by refinancing
higher-cost issues. New issues during 1993 through 1995 totaled $2.7 billion and
retirement or repayment of securities totaled $3.4 billion. The retirements
included the redemption of $131 million, $133 million, and $253 million in 1995,
1994, and 1993, respectively, of first mortgage bonds with the proceeds from the
Plant Scherer Unit 4 sales. Composite financing rates for long-term debt and
preferred stock for the years 1993 through 1995, as of year-end, were as
follows:
1995 1994 1993
---------------------------------
Composite interest rate
on long-term debt 6.57% 7.14% 7.86%
Composite preferred
stock dividend rate 6.73 7.11 6.76
- ----------------------------------------------------------------
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
- -----------------------------------------------------------------
Liquidity and Capital Requirements
Cash provided from operations increased by $281 million in 1995, primarily due
to increased revenues and a decrease in interest payments.
The Company estimates that construction expenditures for the years 1996
through 1998 will total $530 million, $537 million and $529 million,
respectively. Investments in transmission and distribution facilities,
enhancements to existing generating plants, and additions of a combustion
turbine generating plant and equipment to comply with the provisions of the
Clean Air Act are planned.
Cash requirements for sinking fund requirements, redemptions announced, and
maturities of long-term debt are expected to total $283 million during 1996
through 1998.
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 1996 through 1998, 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."
As a result of the Energy Policy Act of 1992, the Company is required to pay
a special assessment over a 15-year period beginning in 1993 into a fund which
will be used by the U. S. Department of Energy for the decontamination and
decommissioning of its nuclear enrichment facilities. The Company estimates its
remaining liability to be approximately $31 million as of December 31, 1995. See
Note 1 to the financial statements under "Revenues and Fuel Costs" for
additional information.
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 $975 million of unused credit
8
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 1995 Annual Report
arrangements with banks at the beginning of 1996. 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 amended by Congress. 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 The 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 The 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.
In 1995, the Environmental Protection Agency (EPA) began issuing annual
sulfur dioxide emission allowances through the newly established allowance
trading program. An emission allowance is the authority to emit one ton of
sulfur dioxide during a calendar year. The method for issuing allowances is
based on the fossil fuel consumed from 1985 through 1987 for each affected
generating unit. Emission allowances are transferable and can be bought, sold,
or banked and used in the future.
The sulfur dioxide emission allowance program is expected to minimize the
cost of compliance. The Southern Company's sulfur dioxide compliance strategy is
designed to use allowances as a compliance option.
The 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. Compliance with nitrogen oxide emission
limits was achieved by the installation of new control equipment at 22 of the
original 28 affected generating units. Construction expenditures for Georgia
Power's Phase I compliance totaled approximately $165 million through 1995.
For Phase II sulfur dioxide compliance, The Southern Company could use
emission allowances banked during Phase I, increase fuel switching, install flue
gas desulfurization equipment at selected plants, and/or purchase more
allowances depending on the price and availability of allowances. Also, in Phase
II, equipment to control nitrogen oxide emissions will be installed on
additional system fossil-fired plants as required to meet anticipated Phase II
limits. During the period 1996 to 2000, current compliance strategy could
require total estimated Georgia Power construction expenditures of approximately
$45 million. 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.
Metropolitan Atlanta is classified as a non-attainment area with regard to
the ozone ambient air quality standards. Title I of the Clean Air Act requires
the state of Georgia to conduct specific studies and establish new control rules
- -- affecting sources of nitrogen oxides and volatile organic compounds -- to
achieve attainment by 1999. As the required first step, the state issued rules
for the application of reasonably available control technology to reduce
nitrogen oxide emissions by May 31, 1995. The results of these new rules require
9
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 1995 Annual Report
nitrogen oxide controls, above Title IV requirements, on some of the Company's
plants. The EPA along with 37 states is conducting studies to evaluate the
benefits of regional controls in meeting the ozone standards. Final attainment
rules, based on modeling studies, could require installation of additional
controls for nitrogen oxide emissions to meet the 1999 deadline or as part of
any regional controls if enacted. A decision on new requirements is expected in
1997. Compliance with any new rules could result in significant additional
costs. The actual impact of new rules will depend on the development and
implementation of such rules.
Title III of the Clean Air Act requires a multi-year EPA study of power
plant emissions of hazardous air pollutants. The EPA is scheduled to submit a
report to Congress on the results of this study during 1996. The report will
include a decision on whether additional regulatory control of these substances
is warranted. Compliance with any new control standards could result in
significant additional costs. The impact of new standards -- if any -- will
depend on the development and implementation of applicable regulations.
The EPA is evaluating the need to revise the ambient air quality standards
for particulate matter and ozone. The impact of any new standard will depend on
the level chosen for the standard and cannot be determined at this time.
In 1996, the EPA may issue revised rules on air quality control regulations
related to stack height requirements of the Clean Air Act. The full impact of
the final rules cannot be determined at this time, pending their development and
implementation.
In 1993, the EPA issued a ruling confirming the non-hazardous status of coal
ash. However, the EPA has until 1998 to classify co-managed utility wastes --
coal ash and other utility wastes -- as either non-hazardous or hazardous. If
the EPA classifies the co-managed wastes as hazardous, then substantial
additional costs for the management of such wastes may be required. The full
impact of any change in the regulatory status will depend on the subsequent
development of co-managed waste requirements.
The 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 $8 million in 1995
and 1994, and $32 million in 1993. Additional sites may require environmental
remediation for which the Company may be liable for a portion of or all required
cleanup 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 these requirements
cannot be determined at this time, pending the development and implementation of
applicable regulations.
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.
10
<PAGE>
<TABLE>
<CAPTION>
STATEMENTS OF INCOME
For the Years Ended December 31, 1995, 1994, and 1993
Georgia Power Company 1995 Annual Report
==========================================================================================================================
1995 1994 1993
- --------------------------------------------------------------------------------------------------------------------------
(in thousands)
<S> <C> <C> <C>
Operating Revenues:
Revenues $4,328,432 $4,101,504 $4,389,513
Revenues from affiliates 76,906 60,899 61,668
- --------------------------------------------------------------------------------------------------------------------------
Total operating revenues 4,405,338 4,162,403 4,451,181
- --------------------------------------------------------------------------------------------------------------------------
Operating Expenses:
Operation --
Fuel 900,973 870,653 951,507
Purchased power from non-affiliates 183,009 193,130 313,170
Purchased power from affiliates 131,740 158,063 194,024
Provision for separation benefits 10,607 82,238 -
Other 735,918 643,375 675,284
Maintenance 292,029 272,818 284,521
Depreciation and amortization 421,850 379,158 379,425
Amortization of deferred Plant Vogtle costs, net (Note 3) 124,454 74,888 36,284
Taxes other than income taxes 204,675 194,566 192,671
Federal and state income taxes 449,204 399,413 452,122
- --------------------------------------------------------------------------------------------------------------------------
Total operating expenses 3,454,459 3,268,302 3,479,008
- --------------------------------------------------------------------------------------------------------------------------
Operating Income 950,879 894,101 972,173
Other Income (Expense):
Allowance for equity funds used during construction 2,734 5,663 3,168
Equity in earnings of unconsolidated subsidiary (Note 4) 4,051 3,588 4,127
Interest income 5,524 3,254 3,806
Other, net (8,973) 10,626 11,902
Income taxes applicable to other income 3,022 7,975 37,661
- --------------------------------------------------------------------------------------------------------------------------
Income Before Interest Charges 957,237 925,207 1,032,837
- --------------------------------------------------------------------------------------------------------------------------
Interest Charges:
Interest on long-term debt 254,607 306,473 343,634
Allowance for debt funds used during construction (12,081) (11,571) (8,271)
Interest on interim obligations 21,463 17,529 15,530
Amortization of debt discount, premium, and expense, net 15,835 15,743 14,024
Other interest charges 20,399 23,483 47,393
- --------------------------------------------------------------------------------------------------------------------------
Net interest charges 300,223 351,657 412,310
- --------------------------------------------------------------------------------------------------------------------------
Net Income 657,014 573,550 620,527
Dividends on Preferred Stock 48,152 48,006 50,674
==========================================================================================================================
Net Income After Dividends on Preferred Stock $ 608,862 $ 525,544 $ 569,853
==========================================================================================================================
The accompanying notes are an integral part of these statements.
</TABLE>
11
<PAGE>
<TABLE>
<CAPTION>
STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 1995, 1994, and 1993
Georgia Power Company 1995 Annual Report
===========================================================================================================================
1995 1994 1993
- ---------------------------------------------------------------------------------------------------------------------------
(in thousands)
<S> <C> <C> <C>
Operating Activities:
Net income $ 657,014 $ 573,550 $ 620,527
Adjustments to reconcile net income to net
cash provided by operating activities --
Depreciation and amortization 527,310 484,032 475,152
Deferred income taxes and investment tax credits, net 37,150 33,567 150,735
Allowance for equity funds used during construction (2,734) (5,663) (3,168)
Amortization of deferred Plant Vogtle costs, net 124,454 74,888 36,284
Non-cash portion of separation benefits - 68,599 -
Gain on asset sales (23,588) (22,717) (35,514)
Other, net 23,722 (72,597) (10,713)
Changes in certain current assets and liabilities --
Receivables, net (59,370) 67,218 27,088
Inventories 30,761 (63,545) 82,433
Payables 45,882 5,409 17,364
Taxes accrued 11,373 (60,474) 15,377
Energy cost recovery, retail 42,576 55,505 (74,260)
Other 3,473 (706) (35,691)
- ---------------------------------------------------------------------------------------------------------------------------
Net cash provided from operating activities 1,418,023 1,137,066 1,265,614
- ---------------------------------------------------------------------------------------------------------------------------
Investing Activities:
Gross property additions (480,449) (638,426) (674,432)
Sales of property 131,099 132,644 261,687
Other (42,579) (41,273) (43,154)
- ---------------------------------------------------------------------------------------------------------------------------
Net cash used for investing activities (391,929) (547,055) (455,899)
- ---------------------------------------------------------------------------------------------------------------------------
Financing Activities:
Proceeds --
Preferred securities - 100,000 -
Preferred stock - - 175,000
First mortgage bonds 75,000 - 1,135,000
Pollution control bonds 504,700 527,210 145,425
Long-term notes - - 37,000
Retirements --
Preferred stock - - (245,005)
First mortgage bonds (505,789) (133,559) (1,337,822)
Pollution control bonds (504,810) (510,320) (145,465)
Other long-term debt (37,000) (10,187) (19,451)
Interim obligations, net (24,472) (57,425) (51,444)
Payment of preferred stock dividends (48,419) (47,147) (53,123)
Payment of common stock dividends (451,500) (429,300) (402,400)
Miscellaneous (17,413) (22,640) (63,648)
- ---------------------------------------------------------------------------------------------------------------------------
Net cash used for financing activities (1,009,703) (583,368) (825,933)
- ---------------------------------------------------------------------------------------------------------------------------
Net Change in Cash and Cash Equivalents 16,391 6,643 (16,218)
Cash and Cash Equivalents at Beginning of Year 12,539 5,896 22,114
- ---------------------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of Year $ 28,930 $ 12,539 $ 5,896
===========================================================================================================================
Supplemental Cash Flow Information:
Cash paid during the year for --
Interest (net of amount capitalized) $ 298,482 $ 336,155 $ 420,107
Income taxes 404,129 386,653 275,867
- ---------------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these statements.
</TABLE>
12
<PAGE>
<TABLE>
<CAPTION>
BALANCE SHEETS
At December 31, 1995 and 1994
Georgia Power Company 1995 Annual Report
=====================================================================================
ASSETS 1995 1994
- -------------------------------------------------------------------------------------
(in thousands)
<S> <C> <C>
Utility Plant:
Plant in service $ 14,538,595 $14,054,917
Less accumulated provision for depreciation 4,417,120 4,054,986
- -------------------------------------------------------------------------------------
10,121,475 9,999,931
Nuclear fuel, at amortized cost 124,849 136,425
Construction work in progress (Note 4) 236,715 541,889
- -------------------------------------------------------------------------------------
Total 10,483,039 10,678,245
- -------------------------------------------------------------------------------------
Other Property and Investments:
Southern Electric Generating Company, at equity (Note 4) 27,232 26,985
Nuclear decommissioning trusts, at market 92,273 54,297
Miscellaneous 120,383 89,542
- -------------------------------------------------------------------------------------
Total 239,888 170,824
- -------------------------------------------------------------------------------------
Current Assets:
Cash and cash equivalents 28,930 12,539
Receivables-
Customer accounts receivable 418,749 377,570
Other accounts receivable 102,953 104,989
Affiliated companies 15,482 14,443
Accumulated provision for uncollectible accounts (5,000) (4,500)
Fossil fuel stock, at average cost 145,151 169,252
Materials and supplies, at average cost 286,804 293,464
Prepayments 107,764 55,383
Vacation pay deferred 35,543 40,823
- -------------------------------------------------------------------------------------
Total 1,136,376 1,063,963
- -------------------------------------------------------------------------------------
Deferred Charges:
Deferred charges related to income taxes (Note 8) 871,783 919,750
Deferred Plant Vogtle costs (Note 3) 307,638 432,092
Premium on reacquired debt, being amortized 174,018 164,676
Debt expense, being amortized 27,227 26,223
Miscellaneous 230,306 256,885
- -------------------------------------------------------------------------------------
Total 1,610,972 1,799,626
- -------------------------------------------------------------------------------------
Total Assets $13,470,275 $13,712,658
=====================================================================================
The accompanying notes are an integral part of these statements.
</TABLE>
13
<PAGE>
<TABLE>
<CAPTION>
BALANCE SHEETS
At December 31, 1995 and 1994
Georgia Power Company 1995 Annual Report
=================================================================================================
CAPITALIZATION AND LIABILITIES 1995 1994
- -------------------------------------------------------------------------------------------------
(in thousands)
<S> <C> <C>
Capitalization (See accompanying statements):
Common stock equity $ 4,299,012 $4,141,554
Preferred stock 692,787 692,787
Subsidiary obligated mandatorily redeemable preferred securities 100,000 100,000
Long-term debt 3,315,460 3,757,823
- -------------------------------------------------------------------------------------------------
Total 8,407,259 8,692,164
- -------------------------------------------------------------------------------------------------
Current Liabilities:
Long-term debt due within one year (Note 9) 150,446 167,420
Notes payable to banks (Note 9) 178,000 202,200
Commercial paper (Note 9) 222,330 222,602
Accounts payable-
Affiliated companies 72,878 41,760
Other 316,278 313,307
Customer deposits 53,145 47,017
Taxes accrued-
Federal and state income 7,759 2,856
Other 96,633 90,163
Interest accrued 96,162 110,256
Vacation pay accrued 34,233 39,720
Miscellaneous 137,184 70,006
- -------------------------------------------------------------------------------------------------
Total 1,365,048 1,307,307
- -------------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes (Note 8) 2,510,458 2,477,661
Accumulated deferred investment tax credits 432,184 453,121
Deferred credits related to income taxes (Note 8) 410,016 433,334
Disallowed Plant Vogtle capacity buyback costs (Note 4) 58,514 60,490
Miscellaneous 286,796 288,581
- -------------------------------------------------------------------------------------------------
Total 3,697,968 3,713,187
- -------------------------------------------------------------------------------------------------
Commitments and Contingent Matters (Notes 1, 2, 3, 4, 5, 6, and 7)
Total Capitalization and Liabilities $13,470,275 $13,712,658
==================================================================================================
The accompanying notes are an integral part of these statements.
</TABLE>
14
<PAGE>
<TABLE>
<CAPTION>
STATEMENTS OF CAPITALIZATION
At December 31, 1995 and 1994
Georgia Power Company 1995 Annual Report
- ----------------------------------------------------------------------------------------------------------------------------------
1995 1994 1995 1994
- ----------------------------------------------------------------------------------------------------------------------------------
(in thousands) (percent of total)
<S> <C> <C>
Common Stock Equity:
Common stock, without par value --
Authorized -- 15,000,000 shares
Outstanding -- 7,761,500 shares $ 344,250 $ 344,250
Paid-in capital 2,384,444 2,384,348
Premium on preferred stock 413 413
Retained earnings (Note 9) 1,569,905 1,412,543
- ----------------------------------------------------------------------------------------------------------------------------------
Total common stock equity 4,299,012 4,141,554 51.1% 47.6%
- ----------------------------------------------------------------------------------------------------------------------------------
Cumulative Preferred Stock, without par value:
Authorized -- 55,000,000 shares
Outstanding -- 21,027,864 shares
$100 stated value --
4.60% to 6.60% 117,787 117,787
7.72% to 7.80% 105,000 105,000
$25 stated value --
$1.90 to $2.125 295,000 295,000
Adjustable rate -- at January 1, 1996:
4.85% 100,000 100,000
5.27% 75,000 75,000
- ----------------------------------------------------------------------------------------------------------------------------------
Total (annual dividend requirement -- $46,608,000) 692,787 692,787 8.2 8.0
- ----------------------------------------------------------------------------------------------------------------------------------
Subsidiary Obligated Mandatorily
Redeemable Preferred Securities (Note 9):
$25 stated value -- 9% 100,000 100,000
- ----------------------------------------------------------------------------------------------------------------------------------
Total (annual distribution requirement -- $9,000,000) 100,000 100,000 1.2 1.2
- ----------------------------------------------------------------------------------------------------------------------------------
Long-Term Debt:
First mortgage bonds --
Maturity Interest Rates
September 1, 1995 5 1/8% - 130,000
March 1, 1996 4 3/4% 150,000 150,000
April 1, 1998 5 1/2% 100,000 100,000
September 1, 1999 6 1/8% 195,000 195,000
2000 through 2003 6% to 7% 625,000 625,000
2008 6 7/8% 50,000 50,000
2019 9.23% - 36,157
2022 through 2025 7.55% to 8 3/4% 595,368 660,000
2032 variable rates - 200,000
- ----------------------------------------------------------------------------------------------------------------------------------
Total first mortgage bonds 1,715,368 2,146,157
Pollution control obligations (Note 9) 1,678,030 1,678,140
Other long-term debt (Note 9) 87,400 124,686
Unamortized debt premium (discount), net (14,892) (23,740)
- ----------------------------------------------------------------------------------------------------------------------------------
Total long-term debt (annual interest
requirement -- $228,539,000) 3,465,906 3,925,243
Less amount due within one year (Note 9) 150,446 167,420
- ----------------------------------------------------------------------------------------------------------------------------------
Long-term debt excluding amount due within one year 3,315,460 3,757,823 39.5 43.2
- ----------------------------------------------------------------------------------------------------------------------------------
Total Capitalization $ 8,407,259 $ 8,692,164 100.0% 100.0%
==================================================================================================================================
The accompanying notes are an integral part of these statements.
15
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
STATEMENTS OF RETAINED EARNINGS
For the Years Ended December 31, 1995, 1994, and 1993
Georgia Power Company 1995 Annual Report
- ----------------------------------------------------------------------------------------------------------------------------------
1995 1994 1993
- ----------------------------------------------------------------------------------------------------------------------------------
(in thousands)
<S> <C> <C> <C>
Balance at Beginning of Period $ 1,412,543 $ 1,316,447 $ 1,159,380
Net income after dividends on preferred stock 608,862 525,544 569,853
Cash dividends on common stock (451,500) (429,300) (402,400)
Preferred stock transactions, net - (148) (10,386)
==================================================================================================================================
Balance at End of Period (Note 9) $ 1,569,905 $ 1,412,543 $ 1,316,447
==================================================================================================================================
</TABLE>
<TABLE>
<CAPTION>
STATEMENTS OF PAID-IN CAPITAL
For the Years Ended December 31, 1995, 1994, and 1993
Georgia Power Company 1995 Annual Report
- ----------------------------------------------------------------------------------------------------------------------------------
1995 1994 1993
- ----------------------------------------------------------------------------------------------------------------------------------
(in thousands)
<S> <C> <C> <C>
Balance at Beginning of Period $ 2,384,348 $ 2,384,348 $ 2,384,140
Contributions to capital by parent company 96 - 208
==================================================================================================================================
Balance at End of Period $ 2,384,444 $ 2,384,348 $ 2,384,348
==================================================================================================================================
The accompanying notes are an integral part of these statements.
16
</TABLE>
<PAGE>
NOTES TO FINANCIAL STATEMENTS
Georgia Power Company 1995 Annual Report
1. SUMMARY OF SIGNIFICANT ACCOUNTING
POLICIES
General
The Company is a wholly owned subsidiary of The Southern Company, which is the
parent company of five operating companies, Southern Company Services (SCS), a
system service company, Southern Communications Services (Southern
Communications), Southern Electric International (Southern Electric), 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 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 The 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 Electric designs, builds, owns, and operates power
production and delivery facilities and provides a broad range of technical
services to industrial companies and utilities in the United States and a number
of international markets. Southern Nuclear provides services to The Southern
Company's nuclear power plants. Southern Development develops new business
opportunities related to energy products and services.
The Southern Company is registered as a holding company under the Public
Utility Holding Company Act of 1935 (PUHCA). Both The Southern Company and its
subsidiaries are subject to the regulatory provisions of this act. The Company
is also subject to regulation by the FERC and the Georgia Public Service
Commission (GPSC). The Company follows generally accepted accounting principles
(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:
1995 1994
--------------------
(in millions)
Deferred income taxes $ 872 $ 920
Deferred income tax credits (410) (433)
Deferred Plant Vogtle costs 308 432
Premium on reacquired debt 174 165
Demand-side program costs 79 97
Corporate building lease 49 48
Postretirement benefits 53 41
Vacation pay 36 41
Inventory conversions (31) (39)
Department of Energy assessments 33 36
Other, net 36 52
==============================================================
Total $1,199 $1,360
==============================================================
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.
17
<PAGE>
NOTES (continued)
Georgia Power Company 1995 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 1995, 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 $86
million in 1995, $87 million in 1994, and $75 million in 1993. 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 2009 at Plant Vogtle.
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, 1995, to be approximately $31 million. This obligation is recorded
in the accompanying Balance Sheets.
Depreciation and Nuclear Decommissioning
Depreciation of the original cost of depreciable utility plant in service is
provided primarily by using composite straight-line rates, which approximated
3.2 percent in 1995 and 3.1 percent in 1994 and 1993. See Note 3 under "Retail
Rate Plan" for additional information. When property subject to depreciation is
retired or otherwise disposed of in the normal course of business, its cost --
together with the cost of removal, less salvage -- is charged to the accumulated
provision for depreciation. Minor items of property included in the original
cost of the plant are retired when the related property unit is retired.
Depreciation expense includes an amount for the expected costs of
decommissioning nuclear facilities and removal of other facilities.
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 approved
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.
The 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
18
<PAGE>
NOTES (continued)
Georgia Power Company 1995 Annual Report
date. The estimated costs of decommissioning -- both site study costs and
ultimate costs at December 31, 1995 -- 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 1995 $11 $ 9
Accumulated provisions:
Balance in external trust funds $56 $36
Balance in internal reserves 30 13
============================================================
Total $86 $49
============================================================
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 --
sinking fund -- 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 under plans that meet the requirements of FASB Statement No. 92,
Accounting for Phase-In Plans. In 1991, the GPSC modified the phase-in plans. In
addition, the Company deferred certain Plant Vogtle operating expenses and
financing costs under accounting orders issued by the GPSC. See Note 3 for
further information.
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 1995, 1994 and 1993, the average AFUDC rates
were 6.53 percent, 6.18 percent and 4.96 percent, respectively. The increase in
1994 is primarily the result of the higher short-term borrowing rates. AFUDC,
net of taxes, as a percentage of net income after dividends on preferred stock,
was less than 2.5 percent for 1995, 1994, and 1993.
19
<PAGE>
NOTES (continued)
Georgia Power Company 1995 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; appropriate administrative and general costs; 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
In accordance with FASB Statement No. 107, Disclosure About Fair Value of
Financial Instruments, the Company's financial instruments for which the
carrying amounts did not approximate fair value at December 31 are as follows:
Carrying Fair
Amount Value
--------------------------
Long-term debt: (in millions)
At December 31, 1995 $3,378 $3,487
At December 31, 1994 3,838 3,697
Preferred Securities:
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 1995 and 1994, the Company funded $21 million and $22 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. As a result of the regulatory treatment allowed by the GPSC, the adoption
of Statement No. 106 did not have a material impact on net income.
20
<PAGE>
NOTES (continued)
Georgia Power Company 1995 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
---------------------
1995 1994
---------------------
Actuarial present value of (in millions)
benefit obligations:
Vested benefits $ 830 $ 689
Non-vested benefits 43 32
- ---------------------------------------------------------------
Accumulated benefit obligation 873 721
Additional amounts related
to projected salary increases 290 294
- ---------------------------------------------------------------
Projected benefit obligation 1,163 1,015
Less:
Fair value of plan assets 1,688 1,419
Unrecognized net gain (465) (371)
Unrecognized prior service cost 26 28
Unrecognized transition asset (52) (58)
===============================================================
Prepaid asset recognized in
the Balance Sheets $ 34 $ 3
===============================================================
Postretirement
Benefits
---------------------
1995 1994
---------------------
(in millions)
Actuarial present value of benefit obligation:
Retirees and dependents $214 $203
Employees eligible to retire 16 7
Other employees 188 229
- ---------------------------------------------------------------
Accumulated benefit obligation 418 439
Less:
Fair value of plan assets 81 52
Unrecognized net loss (gain) 44 (1)
Unrecognized transition
obligation 186 301
===============================================================
Accrued liability recognized in the
Balance Sheets $107 $ 87
===============================================================
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 postretirement benefits. This change reduced the 1995 accumulated
postretirement benefit obligation by approximately $97 million.
The weighted average rates used in actuarial calculations were:
1995 1994 1993
-------------------------------
Discount 7.3% 8.0% 7.5%
Annual salary increase 4.8 5.5 5.0
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 9.8 percent for 1995, decreasing gradually to 5.3 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, 1995, by $39 million and the aggregate of the
service and interest cost components of the net postretirement cost by $8
million.
The components of the plans' net costs are shown below:
Pension
-----------------------------
1995 1994 1993
-----------------------------
(in millions)
Benefits earned during the year $ 33 $ 34 $ 33
Interest cost on projected
benefit obligation 78 71 69
Actual (return) loss on plan assets (317) 35 (194)
Net amortization and deferral 185 (160) 84
================================================================
Net pension cost $ (21) $ (20) $ (8)
================================================================
Net pension costs were negative in 1995, 1994 and 1993. Of net pension
amounts recorded, $15 million in 1995 and 1994, and $6 million in 1993 were
recorded as a
21
<PAGE>
NOTES (continued)
Georgia Power Company 1995 Annual Report
reduction to operating expense, and the remainder was recorded as a reduction
to construction and other accounts.
Postretirement Benefits
--------------------------
1995 1994 1993
--------------------------
(in millions)
Benefits earned during the year $13 $15 $14
Interest cost on accumulated
benefit obligation 34 33 29
Amortization of transition
obligation 16 15 15
Actual (return) loss on plan
assets (8) 1 (4)
Net amortization and deferral 4 (3) 2
==================================================================
Net postretirement cost $59 $61 $56
==================================================================
Of the above net postretirement benefit costs recorded, $33 million in 1995,
$28 million in 1994, and $21 million in 1993 were charged to operating expenses.
In addition, $11 million in 1995, $18 million in 1994, and $21 million in 1993
were deferred, and the remainder was charged to construction and other accounts
Work Force Reduction Programs
The Company has incurred additional costs for work force reduction programs. The
costs related to these programs were $11 million and $82 million for the years
1995 and 1994, respectively. Additionally, in 1994, the Company recognized $8
million for its share of costs associated with SCS's work force reduction
program.
3. REGULATORY AND LITIGATION MATTERS
Retail Rate Plan
On February 16, 1996, the GPSC approved a rate plan recommended by the
Commission staff which concludes the GPSC's review of the Company's earnings
initiated in early 1995 and addresses the Company's proposed alternative retail
rate plan. Under the three-year plan effective January 1, 1996, the Company's
earnings will be 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 plan's three-year operation, including $14 million annually
of accelerated depreciation of electric plant. During the plan'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 plan,
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 rate plan or adopt a
different one.
Rocky Mountain Plant Status
In its 1985 financing order, the GPSC concluded that completion of the Rocky
Mountain pumped storage hydroelectric plant in 1991, as then planned, was not
economically justifiable and reasonable and withheld authorization for the
Company to spend funds from approved securities issuances on that plant. In
1988, the Company and 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. However, full recovery of the Company's costs depends on
the GPSC's treatment of the plant's costs and disposition of the plant's
capacity output. 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. AFUDC
accrued on the Rocky Mountain plant was not credited to income or included in
the plant's cost since December 1985. In 1995, the plant went into commercial
operation. At December 31, 1995, the Company's net investment in the plant was
approximately $190 million, and the Company's ownership was 25.4 percent.
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.
Demand-Side Conservation Programs
In October 1993, a Superior Court of Fulton County, Georgia, judge ruled that
rate riders previously approved by the GPSC for recovery of the Company's costs
incurred in connection with demand-side conservation programs were unlawful. The
judge held that the GPSC lacked statutory authority to approve such rate riders
except through general rate case proceedings and that those procedures had not
been followed. The Company suspended collection of the demand-side conservation
22
<PAGE>
NOTES (continued)
Georgia Power Company 1995 Annual Report
costs and appealed the court's decision to the Georgia Court of Appeals. In
December 1993, the GPSC approved the Company's request for an accounting order
allowing the Company to defer all current unrecovered and future costs related
to these programs until the Superior Court's decision is reversed or until the
next general rate case proceedings.
After the Georgia Court of Appeals upheld the legality of the rate riders,
the Company resumed collection under the rate riders in December 1994. 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.
Under the Retail Rate Plan 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. Any
change in the rate of return on common equity that could potentially require
refunds as a result of this proceeding would be substantially for the period
beginning in July 1991 and ending in October 1992.
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. The second period under
review for possible refunds began in October 1994 and ended in December 1995. 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 and
refunds were ordered, the amount of refunds could range up to approximately $49
million at December 31, 1995. 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, 1995, the Company
has recognized $3.5 million in expenses associated with this site. While the
Company believes that the total amount of costs required for the clean up of
this site may be substantial, it is unable at this time to estimate either such
total or the portion for which the Company may ultimately be responsible.
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 these 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
24 sites which may require environmental remediation by the Company. The
majority of these 24 sites are electrical power substations and power generation
facilities. The Company has recognized $10 million in expenses through December
31, 1995 for the anticipated clean-up cost for 18 sites that the Company plans
23
<PAGE>
NOTES (continued)
Georgia Power Company 1995 Annual Report
to remediate. The Company will conduct studies at each of the remaining sites to
determine the extent of remediation and associated clean-up costs, if any, that
may be required. The Company has recognized $2.4 million in expenses for the
anticipated cost of completing such studies. Any cost of remediating the
remaining sites cannot presently be determined until such studies are completed
for each site and the State of Georgia determines whether remediation is
required. If all listed sites were required to be remediated, the Company could
incur expenses of up to approximately $15 million in additional clean-up costs
and construction expenditures of up to approximately $100 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. The Company's response sought dismissal of the complaint by the FERC.
Dismissal was ordered in November 1994. OPC and MEAG filed a request for
rehearing in December 1994, and the FERC denied such request in July 1995. In
September 1995, OPC appealed the FERC's decision on this issue to the Court of
Appeals for the District of Columbia Circuit.
In August 1994, OPC and MEAG also filed a complaint in the Superior Court of
Fulton County, Georgia, urging substantially the same claims and asking the
court to hear the matter in the event the FERC declines jurisdiction. Such court
proceeding was subsequently stayed pending resolution of the FERC filing.
Plant Vogtle Phase-In Plans
Pursuant to orders from the GPSC, the Company recorded a deferred return under
phase-in plans for Plant Vogtle Units 1 and 2 until October 1991 when the
allowed investment was fully reflected in rates. In addition, the GPSC issued
two separate accounting orders that required the Company to defer substantially
all operating and financing costs related to both units until rate orders
addressed these costs. These GPSC orders provide for the recovery of deferred
costs within 10 years. The GPSC modified the phase-in plans in 1991 to
accelerate the recognition of costs previously deferred under the Plant Vogtle
Unit 2 phase-in plan and to levelize the remaining Plant Vogtle declining
capacity buyback expenses.
Under these orders, the Company has deferred and amortized these costs (as
recovered through rates) as follows:
1995 1994 1993
-----------------------------
(in millions)
Deferred costs at beginning
of year $432 $507 $383
- ----------------------------------------------------------------
Deferred capacity buyback
expenses - 10 38
Amortization of previously
deferred costs (124) (85) (74)
- ----------------------------------------------------------------
Net amortization (124) (75) (36)
- ----------------------------------------------------------------
Effect of adoption of FASB
Statement No. 109 - - 160
================================================================
Deferred costs at end of year $308 $432 $507
================================================================
Nuclear Performance Standards
In October 1989, the GPSC adopted a nuclear performance standard for the
Company's nuclear generating units under which the performance of plants Hatch
and Vogtle will be evaluated every three years. The performance standard is
based on each unit's capacity factor as compared to the average of all U.S.
nuclear units operating at a capacity factor of 50 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. During this three-year period, the Company's units
performed at an average capacity factor of 81 percent compared to an industry
24
<PAGE>
NOTES (continued)
Georgia Power Company 1995 Annual Report
average of approximately 73 percent. Based on these results, the GPSC approved a
performance reward of approximately $8.5 million for the Company. This reward is
being collected through the retail fuel cost recovery provision and recognized
in income over a 36-month period beginning November 1993. At December 31, 1995,
the remaining amount to be collected was $2.4 million.
4. COMMITMENTS
Construction Program
While the Company has no new baseload generating plants under construction, the
construction of one jointly owned combustion turbine peaking unit is planned to
be completed in 1996. 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 $530 million in 1996, $537 million in 1997, and
$529 million in 1998. These estimated additions include AFUDC of $12 million in
1996, $14 million in 1997, and $15 million in 1998. The estimates for property
additions for the three-year period include $67 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.
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,
1995 were as follows:
Minimum
Year Obligations
----------------------
(in millions)
1996 $ 831
1997 678
1998 534
1999 321
2000 231
2001 through 2010 1,624
===============================================================
Total minimum obligations $4,219
===============================================================
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. These commitments are in
effect during periods of up to 10 years following commercial operation (and with
regard to a portion of a 5 percent interest in Plant Vogtle owned by MEAG, until
the latter of the retirement of the plant or the latest stated maturity date of
MEAG's bonds issued to finance such ownership interest). The payments for
capacity are required whether or not any capacity is available. The energy cost
is a function of each unit's variable operating costs. Except as noted below,
the cost of such capacity and energy is included in purchased power from
non-affiliates in the Company's Statements of Income. Capacity payments totaled
$76 million, $129 million and $183 million in 1995, 1994, and 1993,
respectively. The current projected Plant Vogtle capacity payments for the next
five years are: $70 million in 1996, $59 million per year in 1997 through 1999,
and $60 million in 2000. 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.
25
<PAGE>
NOTES (continued)
Georgia Power Company 1995 Annual Report
As discussed in Note 3, 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:
1995 1994 1993
---------------------------------
(in millions)
Energy $44 $43 $60
Capacity 29 33 30
==============================================================
Total $73 $76 $90
==============================================================
Kilowatt-hours 2,391 2,429 3,352
- --------------------------------------------------------------
At December 31, 1995, the capitalization of SEGCO consisted of $54 million
of equity and $78 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. Payments are subject to reductions for failure
to meet minimum capacity output. Total estimated capacity and fixed operation
and maintenance (O&M) payments are as follows:
Fixed
Year Capacity O&M Total
-----------------------------------------
(in millions)
1998 $ 10 $ 3 $ 13
1999 11 4 15
2000 11 4 15
2001 and beyond 178 157 335
================================================================
Total $210 $168 $378
================================================================
Operating Leases
The Company has entered into coal rail car rental agreements with various terms
and expiration dates. These expenses totaled $12 million, $13 million, and $8
million for 1995, 1994, and 1993, respectively. At December 31, 1995, estimated
minimum rental commitments for noncancelable operating leases were as follows:
Year Amounts
-------------------
(in millions)
1996 $ 11
1997 10
1998 10
1999 10
2000 10
2001 and beyond 126
=========================================================
Total minimum payments $177
=========================================================
5. NUCLEAR INSURANCE
Under the Price-Anderson Amendments Act of 1988, the Company maintains
agreements of indemnity with the NRC that, together with private insurance,
cover third-party liability arising from any nuclear incident
26
<PAGE>
NOTES (continued)
Georgia Power Company 1995 Annual Report
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 $12 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 $24 million for excess property damage and $13 million for
replacement power.
For all on-site property damage insurance policies for commercial nuclear
power plants, the NRC requires that the proceeds of such policies issued or
renewed on or after April 2, 1991, shall be dedicated first for the sole purpose
of placing the reactor in a safe and stable condition after an accident. Any
remaining proceeds are to be applied next toward the costs of decontamination
and debris removal operations ordered by the NRC, and any further remaining
proceeds are to be paid either to the Company or to its bond trustees as may be
appropriate under the policies and applicable trust indentures.
The Company participates in an insurance program for nuclear workers that
provides coverage for worker tort claims filed for bodily injury caused at
commercial nuclear power plants. In the event that claims for this insurance
exceed the accumulated reserve funds, the Company could be subject to a maximum
total assessment of $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.
27
<PAGE>
NOTES (continued)
Georgia Power Company 1995 Annual Report
The Scherer Unit 4 transactions were as follows:
Closing Date Percent After-Tax
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.
In 1994, the Company and Florida Power Corporation (FPC) entered into a
joint ownership agreement regarding a 150 megawatt combustion turbine unit to be
constructed at Intercession City, Florida, near Orlando. The unit is scheduled
to begin commercial operation by the end of 1996, and will be constructed,
operated, and maintained by FPC. The Company will have a one-third interest in
the unit, with use of 100 percent of the unit's capacity from June through
September. FPC will have the capacity the remainder of the year. The Company's
investment in the project is expected to be approximately $14 million at
completion.
At December 31, 1995, the Company's percentage ownership and investment
(exclusive of nuclear fuel) in 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) $3,295* $730
Plant Hatch (nuclear) 842 394
Plant Wansley (coal) 297 132
Plant Scherer (coal)
Units 1 and 2 112 39
Unit 3 541 135
Plant McIntosh
Common Facilities
(combustion-turbine) 19 **
Rocky Mountain
(pumped storage) 200 10
- ----------------------------------------------------------------
* Investment net of write-offs.
** Less than $1 million.
28
<PAGE>
NOTES (continued)
Georgia Power Company 1995 Annual Report
7. LONG-TERM POWER SALES AGREEMENTS
The Company and the operating subsidiaries of The 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 have been as follows:
Year Unit Power Sales Non-firm Sales
- -----------------------------------------------------------------
(in millions) (megawatts) (in millions) (megawatts)
1995 $ 53 248 $ - -
1994 75 403 9 101
1993 135 830 17 200
- -----------------------------------------------------------------
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 248 megawatts of capacity in 1995 and is scheduled to sell
approximately 173 megawatts of capacity in 1996. Thereafter, these sales will
decline to an estimated 159 megawatts and remain at that level through 1999.
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
Effective January 1, 1993, the Company adopted FASB Statement No. 109,
Accounting for Income Taxes. The adoption resulted in the recording of
additional deferred income taxes and related regulatory assets and liabilities.
At December 31, 1995, the tax-related regulatory assets were $872 million and
the tax-related regulatory liabilities were $410 million. The assets are
attributable to tax benefits flowed through to customers in prior years and to
taxes applicable to capitalized AFUDC. The liabilities are attributable to
deferred taxes previously recognized at rates higher than current enacted tax
law and to unamortized investment tax credits.
Details of the federal and state income tax provisions are as follows:
1995 1994 1993
------------------------------
Total provision for income taxes: (in millions)
Federal:
Currently payable $349 $306 $223
Deferred -
Current year 84 86 181
Reversal of prior years (55) (57) (40)
Deferred investment tax
credits 1 (1) (18)
- -----------------------------------------------------------------
379 334 346
- -----------------------------------------------------------------
State:
Currently payable 60 52 41
Deferred -
Current year 15 15 31
Reversal of prior years (8) (10) (3)
- -----------------------------------------------------------------
67 57 69
- -----------------------------------------------------------------
Total 446 391 415
- ------------------------------------------------------------------
Less:
Income taxes charged
(credited) to other income (3) (8) (37)
=================================================================
Federal and state income
taxes charged to operations $449 $399 $452
=================================================================
29
<PAGE>
NOTES (continued)
Georgia Power Company 1995 Annual Report
The tax effects of temporary differences between the carrying amounts of
assets and liabilities in the financial statements and their respective tax
bases, which give rise to deferred tax assets and liabilities, are as follows:
1995 1994
--------------------
(in millions)
Deferred tax liabilities:
Accelerated depreciation $1,630 $1,541
Property basis differences 1,074 1,085
Deferred Plant Vogtle costs 100 141
Premium on reacquired debt 70 68
Deferred regulatory costs 38 48
Fuel clause underrecovered - 9
Other 29 23
- ------------------------------------------------------------------
Total 2,941 2,915
- ------------------------------------------------------------------
Deferred tax assets:
Other property basis differences 239 250
Federal effect of state deferred taxes 97 94
Other deferred costs 83 79
Disallowed Plant Vogtle buybacks 25 26
Accrued interest 13 10
Fuel clause overrecovered 6 -
Other 18 13
- ------------------------------------------------------------------
Total 481 472
- ------------------------------------------------------------------
Net deferred tax liabilities 2,460 2,443
Portion included in current assets 51 35
==================================================================
Accumulated deferred income taxes
in the Balance Sheets $2,511 $2,478
==================================================================
Deferred investment tax credits are amortized over the life of the related
property with such amortization normally applied as a credit to reduce
depreciation in the Statements of Income. Credits amortized in this manner
amounted to $22 million in 1995, $25 million in 1994, and $19 million in 1993.
At December 31, 1995, 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:
1995 1994 1993
-----------------------------
Federal statutory rate 35% 35% 35%
State income tax, net of
federal deduction 4 4 4
Non-deductible book
depreciation 2 3 3
Difference in prior years'
deferred and current tax rate (1) (1) (1)
Other - - (1)
================================================================
Effective income tax rate 40% 41% 40%
================================================================
The 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
Common Stock Dividend Restrictions
The Company's first mortgage bond indenture contains various common stock
dividend restrictions that remain in effect as long as the bonds are
outstanding. At December 31, 1995, retained earnings of $897 million were
restricted against the payment of cash dividends on common stock under terms of
the mortgage indenture. Supplemental indentures in connection with future first
mortgage bond issues may contain more stringent common stock dividend
restrictions than those currently in effect.
The Company's charter limits cash dividends on common stock to the lesser of
the retained earnings balance or 75 percent of net income available for such
stock during a prior period of 12 months if the ratio of common stock equity to
total capitalization, including retained earnings, adjusted to reflect the
payment of the proposed dividend, is below 25 percent, and to 50 percent of such
net income if such ratio is less than 20 percent. At December 31, 1995, the
ratio as defined was 50.2 percent.
30
<PAGE>
NOTES (continued)
Georgia Power Company 1995 Annual Report
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 mandatory redeemable preferred
securities. The sole asset of Georgia Power Capital is $103 million aggregate
principal amount of Georgia Power's 9 percent Junior Subordinated Deferrable
Interest Debentures due December 19, 2024. 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 payment obligations with respect to the preferred securities.
Pollution Control Bonds
The Company has incurred obligations in connection with the sale by public
authorities of tax-exempt pollution control and industrial development revenue
bonds. The Company has authenticated and delivered to trustees an aggregate of
$1.5 billion of its first mortgage bonds, which are pledged as security for its
obligations under pollution control and industrial development contracts. No
interest on these first mortgage bonds is payable unless and until a default
occurs on the installment purchase or loan agreements. An aggregate of
approximately $146 million of the pollution control and industrial development
bonds is secured by a subordinated interest in specific property of the Company.
Details of pollution control bonds are as follows:
Maturity Interest Rates 1995 1994
- --------------------------------------------------------------
(in millions)
2000 4.375% $ 50 $ -
2004-2005 5% to 5.70% 143 85
2006-2008 6.375% to 6.75% 12 12
2011-2015 10.125% to 10.6%
& Variable 10 515
2016-2019 6% to 9.375% 282 282
2021-2025 5.40% to 7.25%
& Variable 1,181 784
==============================================================
Total pollution control bonds $ 1,678 $1,678
==============================================================
Bank Credit Arrangements
At the beginning of 1996, the Company had unused credit arrangements with banks
totaling $975 million, of which $514.7 million expires at various times during
1996, $60.3 million expires at May 1, 1998, and $400 million expires at June 30,
1998.
The $400 million expiring June 30, 1998, is under revolving credit
arrangements with several banks providing the Company, Alabama Power Company,
and The 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
The 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 1998, 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 $975 million in unused credit arrangements, a portion
of the lines are dedicated to provide liquidity support to variable rate
pollution control bonds. The credit lines dedicated as of December 31, 1995,
were $475 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 1995.
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
31
<PAGE>
NOTES (continued)
Georgia Power Company 1995 Annual Report
long-term debt. At December 31, 1995 and 1994, the Company had a capitalized
lease obligation for its corporate headquarters building of $87 million and $88
million, respectively, with an interest rate of 8.1 percent. The maturity of
this capital lease obligation through 2000 is approximately as follows: $336
thousand in 1996, $365 thousand in 1997, $395 thousand in 1998, $429 thousand in
1999, and $672 thousand in 2000.
The lease agreement for the corporate headquarters building provides for
payments that are minimal in early years and escalate through the first 21 years
of the lease. For ratemaking purposes, the GPSC has treated the lease as an
operating lease and has allowed only the lease 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, 1995, and 1994, the interest and lease
amortization deferred on the Balance Sheets are $49 million and $48 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.
Long-Term Debt Due Within One Year
The current portion of the Company's long-term debt is as follows:
1995 1994
-----------------
(in millions)
First mortgage bond maturity $150 $130
Other long-term debt - 37
================================================================
Total $150 $167
================================================================
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 Company
currently plans to satisfy its 1996 improvement fund requirement by depositing
cash with the trustee or by pledging additional property.
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 1995 and 1994 is as follows:
Net Income
After
Dividends on
Operating Operating Preferred
Quarter Ended Revenues Income Stock
- -------------------------------------------------------------------
(in millions)
March 1995 $ 974 $207 $ 116
June 1995 1,075 230 149
September 1995 1,374 337 245
December 1995 982 177 99
March 1994 $ 992 $157 $ 58
June 1994 1,030 227 140
September 1994 1,213 331 233
December 1994 927 179 95
- -------------------------------------------------------------------
Earnings in 1994 declined by $55 million as a result of work force reduction
programs recorded primarily in the first quarter.
The Company's business is influenced by seasonal weather conditions.
32
<PAGE>
<TABLE>
<CAPTION>
SELECTED FINANCIAL AND OPERATING DATA
Georgia Power Company 1995 Annual Report
- ----------------------------------------------------------------------------------------------------------------------------------
1995 1994 1993
- ----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Operating Revenues (in thousands) $4,405,338 $4,162,403 $4,451,181
Net Income after Dividends
on Preferred Stock (in thousands) $608,862 $525,544 $569,853
Cash Dividends on Common Stock (in thousands) $451,500 $429,300 $402,400
Return on Average Common Equity (percent) 14.43 12.84 14.37
Total Assets (in thousands) $13,470,275 $13,712,658 $13,736,110
Gross Property Additions (in thousands) $480,449 $638,426 $674,432
- ----------------------------------------------------------------------------------------------------------------------------------
Capitalization (in thousands):
Common stock equity $4,299,012 $4,141,554 $4,045,458
Preferred stock 692,787 692,787 692,787
Preferred stock subject to mandatory redemption - - -
Subsidiary obligated mandatorily redeemable preferred securities 100,000 100,000 -
Long-term debt 3,315,460 3,757,823 4,031,387
- ----------------------------------------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) $8,407,259 $8,692,164 $8,769,632
==================================================================================================================================
Capitalization Ratios (percent):
Common stock equity 51.1 47.6 46.1
Preferred stock 8.2 8.0 7.9
Subsidiary obligated mandatorily redeemable preferred securities 1.2 1.2 -
Long-term debt 39.5 43.2 46.0
- ----------------------------------------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) 100.0 100.0 100.0
==================================================================================================================================
First Mortgage Bonds (in thousands):
Issued 75,000 - 1,135,000
Retired 505,789 133,559 1,337,822
Preferred Stock (in thousands):
Issued - - 175,000
Retired - - 245,005
Subsidiary Obligated Mandatorily Redeemable Preferred Securities (in thousands):
Issued - 100,000 -
- ----------------------------------------------------------------------------------------------------------------------------------
Security Ratings:
First Mortgage Bonds -
Moody's A1 A2 A3
Standard and Poor's A+ A A-
Duff & Phelps AA- A+ A+
Preferred Stock -
Moody's a2 a3 baa1
Standard and Poor's A A- BBB+
Duff & Phelps A A- A-
- ----------------------------------------------------------------------------------------------------------------------------------
Customers (year-end):
Residential 1,500,024 1,466,382 1,441,972
Commercial 198,624 193,648 188,820
Industrial 10,796 10,976 11,217
Other 2,568 2,426 2,322
- ----------------------------------------------------------------------------------------------------------------------------------
Total 1,712,012 1,673,432 1,644,331
==================================================================================================================================
Employees (year-end) 11,061 11,765 12,528
33
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
SELECTED FINANCIAL AND OPERATING DATA
Georgia Power Company 1995 Annual Report
- ----------------------------------------------------------------------------------------------------------------------------------
1992 1991 1990
- ----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Operating Revenues (in thousands) $4,297,436 $4,301,428 $4,445,809
Net Income after Dividends
on Preferred Stock (in thousands) $520,538 $474,855 $208,066
Cash Dividends on Common Stock (in thousands) $384,000 $375,200 $389,600
Return on Average Common Equity (percent) 13.60 12.76 5.52
Total Assets (in thousands) $10,964,442 $10,842,538 $11,176,619
Gross Property Additions (in thousands) $508,444 $548,051 $558,727
- ----------------------------------------------------------------------------------------------------------------------------------
Capitalization (in thousands):
Common stock equity $3,888,237 $3,766,551 $3,673,913
Preferred stock 692,792 607,796 607,796
Preferred stock subject to mandatory redemption 6,250 118,750 125,000
Subsidiary obligated mandatorily redeemable preferred securities - - -
Long-term debt 4,131,016 4,553,189 5,000,225
- ----------------------------------------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) $8,718,295 $9,046,286 $9,406,934
==================================================================================================================================
Capitalization Ratios (percent):
Common stock equity 44.6 41.7 39.1
Preferred stock 8.0 8.0 7.8
Subsidiary obligated mandatorily redeemable preferred securities - - -
Long-term debt 47.4 50.3 53.1
- ----------------------------------------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) 100.0 100.0 100.0
==================================================================================================================================
First Mortgage Bonds (in thousands):
Issued 975,000 - 300,000
Retired 1,381,300 598,384 91,117
Preferred Stock (in thousands):
Issued 195,000 100,000 -
Retired 165,004 100,000 83,750
Subsidiary Obligated Mandatorily Redeemable Preferred Securities (in thousands):
Issued - - -
- ----------------------------------------------------------------------------------------------------------------------------------
Security Ratings:
First Mortgage Bonds -
Moody's A3 Baa1 Baa1
Standard and Poor's A- BBB+ BBB+
Duff & Phelps A- BBB+ BBB
Preferred Stock -
Moody's baa1 baa1 baa1
Standard and Poor's BBB+ BBB BBB
Duff & Phelps BBB BBB- BBB-
- ----------------------------------------------------------------------------------------------------------------------------------
Customers (year-end):
Residential 1,421,175 1,397,682 1,378,888
Commercial 183,784 179,933 178,391
Industrial 11,479 11,946 12,115
Other 2,269 2,190 2,114
- ----------------------------------------------------------------------------------------------------------------------------------
Total 1,618,707 1,591,751 1,571,508
==================================================================================================================================
Employees (year-end) 12,600 13,700 13,746
34A
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
SELECTED FINANCIAL AND OPERATING DATA
Georgia Power Company 1995 Annual Report
- ----------------------------------------------------------------------------------------------------------------------------------
1989 1988 1987
- ----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Operating Revenues (in thousands) $4,145,240 $3,897,479 $3,786,485
Net Income after Dividends
on Preferred Stock (in thousands) $449,099 $479,532 $240,057
Cash Dividends on Common Stock (in thousands) $394,500 $386,600 $377,800
Return on Average Common Equity (percent) 11.72 13.06 6.85
Total Assets (in thousands) $11,372,346 $11,130,539 $11,197,494
Gross Property Additions (in thousands) $727,631 $929,019 $1,034,059
- ----------------------------------------------------------------------------------------------------------------------------------
Capitalization (in thousands):
Common stock equity $3,860,657 $3,806,070 $3,538,182
Preferred stock 607,844 657,844 657,844
Preferred stock subject to mandatory redemption 155,000 162,500 166,250
Subsidiary obligated mandatorily redeemable preferred securities - - -
Long-term debt 5,054,001 4,861,378 4,825,760
- ----------------------------------------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) $9,677,502 $9,487,792 $9,188,036
==================================================================================================================================
Capitalization Ratios (percent):
Common stock equity 39.9 40.1 38.5
Preferred stock 7.9 8.6 9.0
Subsidiary obligated mandatorily redeemable preferred securities - - -
Long-term debt 52.2 51.3 52.5
- ----------------------------------------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) 100.0 100.0 100.0
==================================================================================================================================
First Mortgage Bonds (in thousands):
Issued 250,000 150,000 500,000
Retired 91,516 206,677 217,949
Preferred Stock (in thousands):
Issued - - 125,000
Retired 7,500 3,750 150,000
Subsidiary Obligated Mandatorily Redeemable Preferred Securities (in thousands):
Issued - - -
- ----------------------------------------------------------------------------------------------------------------------------------
Security Ratings:
First Mortgage Bonds -
Moody's Baa2 Baa2 Baa2
Standard and Poor's BBB+ BBB BBB
Duff & Phelps BBB 9 9
Preferred Stock -
Moody's baa2 baa2 baa2
Standard and Poor's BBB BBB- BBB-
Duff & Phelps BBB- 10 10
- ----------------------------------------------------------------------------------------------------------------------------------
Customers (year-end):
Residential 1,355,211 1,329,173 1,303,721
Commercial 177,814 174,147 169,014
Industrial 12,311 12,353 12,307
Other 2,050 1,993 1,858
- ----------------------------------------------------------------------------------------------------------------------------------
Total 1,547,386 1,517,666 1,486,900
==================================================================================================================================
Employees (year-end) 13,900 15,110 14,924
34B
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
SELECTED FINANCIAL AND OPERATING DATA
Georgia Power Company 1995 Annual Report
- -----------------------------------------------------------------------------------------------------------------------
1986 1985
- -----------------------------------------------------------------------------------------------------------------------
<S> <C> <C>
Operating Revenues (in thousands) $3,561,603 $3,609,140
Net Income after Dividends
on Preferred Stock (in thousands) $535,003 $493,717
Cash Dividends on Common Stock (in thousands) $325,500 $277,500
Return on Average Common Equity (percent) 16.51 17.95
Total Assets (in thousands) $10,465,063 $9,030,618
Gross Property Additions (in thousands) $1,598,309 $1,384,182
- -----------------------------------------------------------------------------------------------------------------------
Capitalization (in thousands):
Common stock equity $3,469,201 $3,013,707
Preferred stock 732,844 632,844
Preferred stock subject to mandatory redemption 112,500 120,000
Subsidiary obligated mandatorily redeemable preferred securities - -
Long-term debt 4,464,857 3,878,066
- -----------------------------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) $8,779,402 $7,644,617
=======================================================================================================================
Capitalization Ratios (percent):
Common stock equity 39.5 39.4
Preferred stock 9.6 9.9
Subsidiary obligated mandatorily redeemable preferred securities - -
Long-term debt 50.9 50.7
- -----------------------------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) 100.0 100.0
=======================================================================================================================
First Mortgage Bonds (in thousands):
Issued 500,000 -
Retired 377,538 17,738
Preferred Stock (in thousands):
Issued 100,000 150,000
Retired 7,500 3,750
Subsidiary Obligated Mandatorily Redeemable Preferred Securities (in thousands):
Issued - -
- -----------------------------------------------------------------------------------------------------------------------
Security Ratings:
First Mortgage Bonds -
Moody's Baa1 Baa1
Standard and Poor's BBB+ BBB+
Duff & Phelps 9 9
Preferred Stock -
Moody's baa1 baa1
Standard and Poor's BBB BBB
Duff & Phelps 10 10
- -----------------------------------------------------------------------------------------------------------------------
Customers (year-end):
Residential 1,268,983 1,231,140
Commercial 162,258 155,399
Industrial 12,315 12,309
Other 1,816 1,789
- -----------------------------------------------------------------------------------------------------------------------
Total 1,445,372 1,400,637
=======================================================================================================================
Employees (year-end) 14,773 14,947
34C
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
SELECTED FINANCIAL AND OPERATING DATA (continued)
Georgia Power Company 1995 Annual Report
- ----------------------------------------------------------------------------------------------------------------------------------
1995 1994 1993
- ----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Operating Revenues (in thousands):
Residential $1,337,060 $1,180,358 $1,291,035
Commercial 1,449,108 1,367,315 1,354,130
Industrial 1,141,766 1,100,995 1,113,067
Other 44,255 42,983 41,399
- ----------------------------------------------------------------------------------------------------------------------------------
Total retail 3,972,189 3,691,651 3,799,631
Sales for resale - non-affiliates 290,302 351,591 534,370
Sales for resale - affiliates 76,906 60,899 61,668
- ----------------------------------------------------------------------------------------------------------------------------------
Total revenues from sales of electricity 4,339,397 4,104,141 4,395,669
Other revenues 65,941 58,262 55,512
- ----------------------------------------------------------------------------------------------------------------------------------
Total $4,405,338 $4,162,403 $4,451,181
==================================================================================================================================
Kilowatt-Hour Sales (in thousands):
Residential 17,307,399 15,680,709 16,649,859
Commercial 19,844,999 18,738,461 18,278,508
Industrial 25,286,340 24,337,632 23,635,363
Other 493,720 484,009 460,801
- ----------------------------------------------------------------------------------------------------------------------------------
Total retail 62,932,458 59,240,811 59,024,531
Sales for resale - non-affiliates 6,591,841 7,968,475 14,307,030
Sales for resale - affiliates 2,738,947 3,056,050 3,027,733
- ----------------------------------------------------------------------------------------------------------------------------------
Total 72,263,246 70,265,336 76,359,294
==================================================================================================================================
Average Revenue Per Kilowatt-Hour (cents):
Residential 7.73 7.53 7.75
Commercial 7.30 7.30 7.41
Industrial 4.52 4.52 4.71
Total retail 6.31 6.23 6.44
Sales for resale 3.94 3.74 3.44
Total sales 6.00 5.84 5.76
Residential Average Annual Kilowatt-Hour Use Per Customer 11,654 10,766 11,630
Residential Average Annual Revenue Per Customer $900.28 $810.39 $901.79
Plant Nameplate Capacity Ratings (year-end) (megawatts) 14,344 13,943 13,759
Maximum Peak-Hour Demand (megawatts) (Note):
Winter 9,819 10,509 9,067
Summer 12,828 11,758 12,573
Annual Load Factor (percent) 59.6 63.0 58.5
Plant Availability (percent):
Fossil-steam 85.8 83.1 85.9
Nuclear 91.8 88.4 85.5
- ----------------------------------------------------------------------------------------------------------------------------------
Source of Energy Supply (percent):
Coal 63.0 61.3 62.1
Nuclear 19.3 18.0 16.2
Hydro 2.5 2.6 2.3
Oil and gas 0.6 0.1 0.2
Purchased power -
From non-affiliates 7.7 9.7 10.2
From affiliates 6.9 8.3 9.0
- ----------------------------------------------------------------------------------------------------------------------------------
Total 100.0 100.0 100.0
==================================================================================================================================
Total Fuel Economy Data:
BTU per net kilowatt-hour generated 10,039 9,915 9,912
Cost of fuel per million BTU (cents) 143.85 145.33 153.62
Average cost of fuel per net kilowatt-hour generated (cents) 1.44 1.44 1.52
==================================================================================================================================
Note: As of 9/1/91, Georgia Power Company's sales to Oglethorpe Power Company are not included in Peak-Hour Demand.
* Less than one-tenth of one percent.
35
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
SELECTED FINANCIAL AND OPERATING DATA (continued)
Georgia Power Company 1995 Annual Report
- ----------------------------------------------------------------------------------------------------------------------------------
1992 1991 1990
- ----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Operating Revenues (in thousands):
Residential $1,128,396 $1,111,358 $1,109,165
Commercial 1,285,681 1,243,067 1,218,441
Industrial 1,083,856 1,057,702 1,061,830
Other 39,504 37,861 36,773
- ----------------------------------------------------------------------------------------------------------------------------------
Total retail 3,537,437 3,449,988 3,426,209
Sales for resale - non-affiliates 640,308 736,643 784,086
Sales for resale - affiliates 67,835 65,586 168,251
- ----------------------------------------------------------------------------------------------------------------------------------
Total revenues from sales of electricity 4,245,580 4,252,217 4,378,546
Other revenues 51,856 49,211 67,263
- ----------------------------------------------------------------------------------------------------------------------------------
Total $4,297,436 $4,301,428 $4,445,809
==================================================================================================================================
Kilowatt-Hour Sales (in thousands):
Residential 14,939,172 14,815,089 14,771,648
Commercial 17,260,614 16,885,833 16,627,128
Industrial 22,978,312 22,298,062 22,126,604
Other 436,144 429,016 428,459
- ----------------------------------------------------------------------------------------------------------------------------------
Total retail 55,614,242 54,428,000 53,953,839
Sales for resale - non-affiliates 15,870,222 18,719,924 20,158,681
Sales for resale - affiliates 3,320,060 3,885,892 8,272,528
- ----------------------------------------------------------------------------------------------------------------------------------
Total 74,804,524 77,033,816 82,385,048
==================================================================================================================================
Average Revenue Per Kilowatt-Hour (cents):
Residential 7.55 7.50 7.51
Commercial 7.45 7.36 7.33
Industrial 4.72 4.74 4.80
Total retail 6.36 6.34 6.35
Sales for resale 3.69 3.55 3.35
Total sales 5.68 5.52 5.31
Residential Average Annual Kilowatt-Hour Use Per Customer 10,603 10,675 10,795
Residential Average Annual Revenue Per Customer $800.88 $800.78 $810.56
Plant Nameplate Capacity Ratings (year-end) (megawatts) 14,076 14,076 14,366
Maximum Peak-Hour Demand (megawatts) (Note):
Winter 8,938 10,001 8,977
Summer 11,448 13,090 13,196
Annual Load Factor (percent) 60.5 55.2 55.5
Plant Availability (percent):
Fossil-steam 86.6 93.3 92.5
Nuclear 87.7 81.6 81.3
- ----------------------------------------------------------------------------------------------------------------------------------
Source of Energy Supply (percent):
Coal 61.4 63.6 65.1
Nuclear 17.0 15.3 13.7
Hydro 2.5 2.3 2.2
Oil and gas * * 0.1
Purchased power -
From non-affiliates 12.2 10.3 11.0
From affiliates 6.9 8.5 7.9
- ----------------------------------------------------------------------------------------------------------------------------------
Total 100.0 100.0 100.0
==================================================================================================================================
Total Fuel Economy Data:
BTU per net kilowatt-hour generated 9,900 9,960 9,939
Cost of fuel per million BTU (cents) 153.08 157.97 166.22
Average cost of fuel per net kilowatt-hour generated (cents) 1.52 1.57 1.65
==================================================================================================================================
Note: As of 9/1/91, Georgia Power Company's sales to Oglethorpe Power Company are not included in Peak-Hour Demand.
* Less than one-tenth of one percent.
36A
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
SELECTED FINANCIAL AND OPERATING DATA (continued)
Georgia Power Company 1995 Annual Report
- --------------------------------------------------------------------------------------------------------------------------------
1989 1988 1987
- --------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Operating Revenues (in thousands):
Residential $1,022,781 $979,047 $904,218
Commercial 1,143,727 1,054,995 915,540
Industrial 1,006,416 983,822 911,933
Other 34,775 31,743 29,350
- --------------------------------------------------------------------------------------------------------------------------------
Total retail 3,207,699 3,049,607 2,761,041
Sales for resale - non-affiliates 760,809 707,076 822,696
Sales for resale - affiliates 150,394 86,751 159,998
- --------------------------------------------------------------------------------------------------------------------------------
Total revenues from sales of electricity 4,118,902 3,843,434 3,743,735
Other revenues 26,338 54,045 42,750
- --------------------------------------------------------------------------------------------------------------------------------
Total $4,145,240 $3,897,479 $3,786,485
================================================================================================================================
Kilowatt-Hour Sales (in thousands):
Residential 14,134,195 13,800,038 13,675,730
Commercial 15,843,181 14,790,561 13,799,379
Industrial 21,801,404 21,412,845 20,884,454
Other 414,107 397,669 385,514
- --------------------------------------------------------------------------------------------------------------------------------
Total retail 52,192,887 50,401,113 48,745,077
Sales for resale - non-affiliates 20,479,412 18,544,705 20,910,185
Sales for resale - affiliates 7,489,948 3,327,814 6,032,889
- --------------------------------------------------------------------------------------------------------------------------------
Total 80,162,247 72,273,632 75,688,151
================================================================================================================================
Average Revenue Per Kilowatt-Hour (cents):
Residential 7.24 7.09 6.61
Commercial 7.22 7.13 6.63
Industrial 4.62 4.59 4.37
Total retail 6.15 6.05 5.66
Sales for resale 3.26 3.63 3.65
Total sales 5.14 5.32 4.95
Residential Average Annual Kilowatt-Hour Use Per Customer 10,530 10,484 10,623
Residential Average Annual Revenue Per Customer $761.96 $743.82 $702.36
Plant Nameplate Capacity Ratings (year-end) (megawatts) 14,366 13,018 13,018
Maximum Peak-Hour Demand (megawatts) (Note):
Winter 10,101 9,866 9,446
Summer 12,735 12,295 12,390
Annual Load Factor (percent) 56.3 59.1 56.1
Plant Availability (percent):
Fossil-steam 93.0 94.5 92.7
Nuclear 89.2 69.4 85.4
- --------------------------------------------------------------------------------------------------------------------------------
Source of Energy Supply (percent):
Coal 64.0 72.0 70.9
Nuclear 14.1 9.6 9.1
Hydro 2.1 1.2 1.7
Oil and gas 0.1 0.1 0.1
Purchased power -
From non-affiliates 10.2 8.2 8.5
From affiliates 9.5 8.9 9.7
- --------------------------------------------------------------------------------------------------------------------------------
Total 100.0 100.0 100.0
================================================================================================================================
Total Fuel Economy Data:
BTU per net kilowatt-hour generated 10,020 9,969 9,932
Cost of fuel per million BTU (cents) 164.27 166.28 168.81
Average cost of fuel per net kilowatt-hour generated (cents) 1.65 1.66 1.68
================================================================================================================================
Note: As of 9/1/91, Georgia Power Company's sales to Oglethorpe Power Company are not included in Peak-Hour Demand.
* Less than one-tenth of one percent.
36B
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
SELECTED FINANCIAL AND OPERATING DATA (continued)
Georgia Power Company 1995 Annual Report
- -----------------------------------------------------------------------------------------------------------------------
1986 1985
- -----------------------------------------------------------------------------------------------------------------------
<S> <C> <C>
Operating Revenues (in thousands):
Residential $874,231 $786,500
Commercial 854,755 797,540
Industrial 897,646 873,554
Other 27,948 26,766
- -----------------------------------------------------------------------------------------------------------------------
Total retail 2,654,580 2,484,360
Sales for resale - non-affiliates 780,049 941,743
Sales for resale - affiliates 91,753 149,463
- -----------------------------------------------------------------------------------------------------------------------
Total revenues from sales of electricity 3,526,382 3,575,566
Other revenues 35,221 33,574
- -----------------------------------------------------------------------------------------------------------------------
Total $3,561,603 $3,609,140
=======================================================================================================================
Kilowatt-Hour Sales (in thousands):
Residential 13,234,248 12,006,462
Commercial 12,945,926 11,945,938
Industrial 20,339,235 19,517,543
Other 381,917 382,238
- -----------------------------------------------------------------------------------------------------------------------
Total retail 46,901,326 43,852,181
Sales for resale - non-affiliates 18,198,186 21,526,865
Sales for resale - affiliates 3,160,242 5,999,834
- -----------------------------------------------------------------------------------------------------------------------
Total 68,259,754 71,378,880
=======================================================================================================================
Average Revenue Per Kilowatt-Hour (cents):
Residential 6.61 6.55
Commercial 6.60 6.68
Industrial 4.41 4.48
Total retail 5.66 5.67
Sales for resale 4.08 3.96
Total sales 5.17 5.01
Residential Average Annual Kilowatt-Hour Use Per Customer 10,577 9,923
Residential Average Annual Revenue Per Customer $698.72 $650.01
Plant Nameplate Capacity Ratings (year-end) (megawatts) 11,875 11,875
Maximum Peak-Hour Demand (megawatts) (Note):
Winter 10,551 10,049
Summer 11,910 11,079
Annual Load Factor (percent) 57.5 56.3
Plant Availability (percent):
Fossil-steam 91.2 91.2
Nuclear 64.7 79.5
- -----------------------------------------------------------------------------------------------------------------------
Source of Energy Supply (percent):
Coal 74.6 72.7
Nuclear 5.0 6.7
Hydro 1.2 1.5
Oil and gas 0.6 *
Purchased power -
From non-affiliates 8.9 9.4
From affiliates 9.7 9.7
- -----------------------------------------------------------------------------------------------------------------------
Total 100.0 100.0
=======================================================================================================================
Total Fuel Economy Data:
BTU per net kilowatt-hour generated 10,016 10,089
Cost of fuel per million BTU (cents) 175.81 178.11
Average cost of fuel per net kilowatt-hour generated (cents) 1.76 1.80
=======================================================================================================================
Note: As of 9/1/91, Georgia Power Company's sales to Oglethorpe Power Company are not included in Peak-Hour Demand.
* Less than one-tenth of one percent.
36C
<PAGE>
</TABLE>
