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 15, 1995
----------------------
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
- -----------------------------------------------------------------------
(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, 1994.
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934,
the registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
GEORGIA POWER COMPANY
By /s/ Wayne Boston
-------------------
Wayne Boston
Assistant Secretary
Date: March 1, 1995
Exhibit 23
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the incorporation
of our report dated February 15 1995 on the financial statements of Georgia
Power Company, included in this Form 8-K, into Georgia Power Company's
previously filed Registration Statement File No. 33-49661.
/s/ Arthur Andersen LLP
Atlanta, Georgia
March 1, 1995
<TABLE> <S> <C>
<ARTICLE> UT
<LEGEND>
This schedule 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> 12-MOS
<FISCAL-YEAR-END> DEC-31-1994
<PERIOD-END> DEC-31-1994
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 10,678,245
<OTHER-PROPERTY-AND-INVEST> 170,824
<TOTAL-CURRENT-ASSETS> 1,063,963
<TOTAL-DEFERRED-CHARGES> 1,799,626
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 13,712,658
<COMMON> 344,250
<CAPITAL-SURPLUS-PAID-IN> 2,384,761
<RETAINED-EARNINGS> 1,412,543
<TOTAL-COMMON-STOCKHOLDERS-EQ> 4,141,554
100,000
692,787
<LONG-TERM-DEBT-NET> 3,800,557
<SHORT-TERM-NOTES> 202,200
<LONG-TERM-NOTES-PAYABLE> 37,000
<COMMERCIAL-PAPER-OBLIGATIONS> 222,602
<LONG-TERM-DEBT-CURRENT-PORT> (167,110)
0
<CAPITAL-LEASE-OBLIGATIONS> 87,686
<LEASES-CURRENT> (310)
<OTHER-ITEMS-CAPITAL-AND-LIAB> 4,595,692
<TOT-CAPITALIZATION-AND-LIAB> 13,712,658
<GROSS-OPERATING-REVENUE> 4,162,403
<INCOME-TAX-EXPENSE> 399,413
<OTHER-OPERATING-EXPENSES> 2,868,889
<TOTAL-OPERATING-EXPENSES> 3,268,302
<OPERATING-INCOME-LOSS> 894,101
<OTHER-INCOME-NET> 31,106
<INCOME-BEFORE-INTEREST-EXPEN> 925,207
<TOTAL-INTEREST-EXPENSE> 351,657
<NET-INCOME> 573,550
48,006
<EARNINGS-AVAILABLE-FOR-COMM> 525,544
<COMMON-STOCK-DIVIDENDS> 429,300
<TOTAL-INTEREST-ON-BONDS> 282,112
<CASH-FLOW-OPERATIONS> 1,137,066
<EPS-PRIMARY> 0
<EPS-DILUTED> 0
</TABLE>
<PAGE>
1
MANAGEMENT'S REPORT
Georgia Power Company 1994 Annual Report
The management of Georgia Power Company has prepared this annual report and is
responsible for the financial statements and related information. These
statements were prepared in accordance with generally accepted accounting
principles appropriate in the circumstances, and necessarily include amounts
that are based on the best estimates and judgments of management. Financial
information throughout this annual report is consistent with the financial
statements.
The Company maintains a system of internal accounting controls to provide
reasonable assurance that assets are safeguarded and that the books and records
reflect only authorized transactions of the Company. Limitations exist in any
system of internal controls based upon the recognition that the cost of the
system should not exceed its benefits. The Company believes that its system of
internal accounting controls maintains an appropriate cost/benefit relationship.
The Company's system of internal accounting controls is evaluated on an
ongoing basis by the Company's internal audit staff. The Company's independent
public accountants also consider certain elements of the internal control system
in order to determine their auditing procedures for the purpose of expressing an
opinion on the financial statements.
The audit committee of the board of directors, which is composed of five
directors who are not employees, provides a broad overview of management's
financial reporting and control functions. At least three times a
year this committee meets with management, the internal auditors, and the
independent public accountants to ensure that these groups are fulfilling their
obligations and to discuss auditing, internal control and financial reporting
matters. The internal auditors and the independent public accountants have
access to the members of the audit committee at any time.
Management believes that its policies and procedures provide reasonable
assurance that the Company's operations are conducted with a high standard of
business ethics.
In management's opinion, the financial statements present fairly, in all
material respects, the financial position, results of operations and cash flows
of Georgia Power Company in conformity with generally accepted accounting
principles. As discussed in Note 4 to the financial statements, an uncertainty
exists with respect to the actions of regulators regarding recoverability of the
Company's investment in the Rocky Mountain pumped storage hydroelectric project.
The outcome of this uncertainty cannot be determined until a regulatory review
is completed. Accordingly, no provision for any write-down of the costs
associated with the Rocky Mountain project resulting from the potential actions
of the Georgia Public Service Commission has been made in the accompanying
financial statements.
/s/ H. Allen Franklin
H. Allen Franklin
President and Chief
Executive Officer
/s/ Warren Y. Jobe
Warren Y. Jobe
Executive Vice President,
Treasurer and Chief
Financial Officer
<PAGE>
2
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, 1994 and 1993, 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, 1994. 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 11-33) referred to above
present fairly, in all material respects, the financial position of Georgia
Power Company as of December 31, 1994 and 1993, and the results of its
operations and its cash flows for the periods stated, in conformity with
generally accepted accounting principles.
As explained in Notes 2 and 7 to the financial statements, effective January
1, 1993, the Company changed its methods of accounting for postretirement
benefits other than pensions and for income taxes.
As more fully discussed in Note 4 to the financial statements, an
uncertainty exists with respect to the actions of the regulators regarding
recoverability of the Company's investment in the Rocky Mountain pumped storage
hydroelectric project. The outcome of this uncertainty cannot be determined
until a regulatory review is completed. Accordingly, no provision for any
write-down of the costs associated with the Rocky Mountain project resulting
from the potential actions of the Georgia Public Service Commission has been
made in the accompanying financial statements.
/s/ Arthur Andersen LLP
Atlanta, Georgia
February 15, 1995
<PAGE>
3
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL
CONDITION
Georgia Power Company 1994 Annual Report
RESULTS OF OPERATIONS
Earnings
Georgia Power Company's 1994 earnings totaled $526 million, representing a $44
million (7.8 percent) decrease from the prior year. This decline is primarily
the result of a $55 million after-tax charge associated with the 1994 work force
reduction programs. The Company had lower operating expenses and financing costs
in 1994, partially offset by lower retail revenues due to the mild weather.
Also, during the period, the Company had an $11 million after-tax gain on the
sale of a portion of Plant Scherer Unit 4 compared to an $18 million after-tax
gain on the sale of a portion of the plant in the prior year.
Earnings for 1993 increased over the prior year primarily as a result of
higher retail revenues due to the exceptionally hot summer weather during 1993
and lower financing costs. Also, as previously discussed, 1993 earnings included
an $18 million after-tax gain on the sale of a portion of Plant Scherer. These
positive events were partially offset by higher operating expenses.
Revenues
The following table summarizes the factors impacting operating revenues for the
1992-1994 period:
==========================================================
Increase (Decrease)
From Prior Year
- ----------------------------------------------------------
1994 1993 1992
--------------------------
Retail - (in millions)
Change in base rates $ - $ - $ 95
Sales growth 67 45 76
Weather (128) 126 (58)
Fuel cost recovery (35) 76 (26)
Demand-side programs (12) 15 -
- ----------------------------------------------------------
Total retail (108) 262 87
- ----------------------------------------------------------
Sales for resale -
Non-affiliates (183) (106) (96)
Affiliates (1) (6) 2
- ----------------------------------------------------------
Total sales for resale (184) (112) (94)
- ----------------------------------------------------------
Other operating revenues 3 4 3
- ----------------------------------------------------------
Total operating revenues $(289) $ 154 $ (4)
==========================================================
Percent change (6.5)% 3.6% (0.1)%
- ----------------------------------------------------------
Retail revenues of $3.7 billion in 1994 decreased $108 million (2.8 percent)
from the prior year, compared with an increase of $262 million (7.4 percent) in
1993. The milder-than-normal weather during the summer of 1994, compared to the
hot summer of 1993, was the primary reason for the decrease in retail revenues.
The hot weather during the summer of 1993 was the primary factor affecting the
increase in retail revenues over 1992. 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 1994 and
1993. Sales to municipalities and cooperatives in Georgia 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 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:
==============================================================
1994 1993 1992
--------------------------
(in millions)
Capacity $84 $152 $233
Energy 82 113 168
- --------------------------------------------------------------
Total $166 $265 $401
==============================================================
Contractual unit power sales to Florida utilities for 1994 and 1993 are down
compared with prior years, primarily due to scheduled reductions that
corresponded with the sales to these utilities of portions of Plant Scherer Unit
4 in June 1994 and June 1993. The amount of capacity under these contracts
declined by 427 megawatts and 533 megawatts in 1994 and 1993, respectively.
In 1995, the contracted capacity will decline another 155 megawatts.
<PAGE>
4
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 1994 Annual Report
Revenues from sales to affiliated companies within the Southern electric
system will vary from year to year depending on demand and the availability and
cost of generating resources at each company. Sales to affiliated companies do
not have a significant impact on earnings.
Kilowatt-hour (KWH) sales for 1994 and the percent change by year were as
follows:
=======================================================================
Percent Change
----------------------------------
1994
KWH 1994 1993 1992
------ ----------------------------------
(in billions)
Residential 15.7 (5.8)% 11.5% 0.8%
Commercial 18.7 2.5 5.9 2.2
Industrial 24.3 3.0 2.9 3.1
Other 0.5 5.0 5.7 1.7
------
Total retail 59.2 0.4 6.1 2.2
------
Sales for resale -
Non-affiliates 8.0 (44.3) (9.8) (15.2)
Affiliates 3.1 0.9 (8.8) (14.6)
------
Total sales for resale 11.1 (36.4) (9.7) (15.1)
------
Total sales 70.3 (8.0) 2.1 (2.9)
======
- -----------------------------------------------------------------------
The sales decline in the residential class was primarily the result of
milder-than-normal summer weather in 1994, compared to the extremely hot summer
of 1993. Industrial and commercial sales were positively impacted by continued
improvement in economic conditions. Residential and commercial energy sales
growth in 1993 reflected hot summer weather. Industrial sales growth in 1993 is
attributable to improved economic conditions which also positively influenced
commercial sales. Assuming normal weather, sales to retail customers are
projected to grow approximately 2 percent annually on average during 1995
through 1997.
Energy sales to non-affiliated utilities reflect reductions in contractual
unit power sales and energy sales to municipalities and cooperatives, as
discussed earlier.
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:
===============================================================================
1994 1993 1992
----------------------------------
Total generation
(billions of kilowatt-hours) 62 64 63
Sources of generation
(percent) --
Coal 74.8 76.9 75.9
Nuclear 21.9 20.0 20.9
Hydro 3.1 2.8 3.1
Oil and gas 0.2 0.3 0.1
Average cost of fuel per net
kilowatt-hour generated
(cents) --
Coal 1.67 1.75 1.75
Nuclear 0.63 0.58 0.63
Oil and gas * * *
Total 1.44 1.52 1.52
- -------------------------------------------------------------------------------
* Not meaningful because of minimal generation from
fuel source.
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. In 1993, fuel expense increased 2.3 percent due to higher
generation, which was partially offset by lower nuclear fuel costs.
Purchased power expense has decreased significantly since 1992, reflecting
declining contractual capacity purchases from the co-owners of plants Vogtle and
Scherer. Purchased power expense decreased $156 million in 1994 and $88 million
in 1993. The decline in 1994 also results from decreased purchases from
affiliated companies and energy purchases from territorial wholesale customers.
The declines in Plant Vogtle contractual capacity purchases did not have a
significant impact on earnings in 1994 or 1993 since these costs are being
levelized over six years under the terms of the 1991 Georgia Public Service
Commission (GPSC) retail rate order. The levelization is reflected in the
amortization of deferred Plant Vogtle expenses in the income statements. See
Note 3 to the financial statements under "Plant Vogtle Phase-In Plans" for
additional information.
<PAGE>
5
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 1994 Annual Report
Other Operation and Maintenance (O & M) expenses, excluding the provision
for separation benefits, decreased 4.5 percent in 1994. The decrease is
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 expenses
and pension costs during 1994. Other O & M expenses increased 9.0 percent in
1993 primarily as a result of environmental remediation costs and the automotive
fleet reduction program, and the recognition of higher employee benefit costs
under new accounting rules adopted in 1993. See Note 2 to the financial
statements under "Postretirement Benefits" for additional information concerning
the new accounting rules. Also, during 1993, O & M expenses reflected costs
associated with new demand-side option programs. These program costs were offset
by increases in retail revenues. See Note 3 to the financial statements under
"Demand-Side Conservation Programs" for additional information on the recovery
of these program costs.
Taxes other than income taxes increased 1.0 percent in 1994 and 7.4 percent
in 1993, reflecting primarily higher ad valorem taxes. The 1993 increase also
includes higher franchise taxes paid to municipalities as a result of increased
sales.
Income tax expense decreased $24 million in 1994 primarily due to lower
earnings and the recognition of $17 million in tax expense associated with the
sale of a portion of Plant Scherer Unit 4 in 1994, compared to $27 million in
tax expense associated with the sale of a portion of the plant in the prior
year. The sales resulted in after-tax gains of $11 million in 1994 and $18
million in 1993. Income tax expense increased $62 million in 1993 due primarily
to higher earnings, the effect of a one percent increase in the federal tax rate
effective January, 1993, and as previously discussed, the sale of a portion of
Plant Scherer Unit 4.
Interest expense and dividends on preferred stock decreased $63 million
(13.7 percent) and $19 million (4.0 percent) in 1994 and 1993, respectively.
These reductions are primarily due to refinancing of long-term debt and
preferred stock. The Company refinanced $510 million and $1.5 billion of
securities in 1994 and 1993, respectively. The Company also retired $386 million
of long-term debt with the proceeds from the 1994 and 1993 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.
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 1995 through 1997.
The scheduled addition of four combustion turbine generating units and the
Rocky Mountain pumped storage hydroelectric project in 1995 and one jointly
owned combustion turbine unit in 1996, will increase related O & M and
<PAGE>
6
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 1994 Annual Report
depreciation expenses. In addition, the Company has entered into a four-year
purchase power agreement to meet peaking needs. Beginning in 1996, the Company
will purchase 400 megawatts of capacity. In 1998, this amount will decline to
200 megawatts for the remaining two years. Capacity payments are projected to be
$6 million in 1996 and 1997 and $3 million in 1998 and 1999. These costs will be
recorded in purchased power expenses in the Statements of Income. The Company
has also reached an agreement on major terms and conditions of a purchase power
arrangement whereby the Company would buy electricity during peak periods from a
proposed 200 megawatt cogeneration facility, starting in June 1998. A final
agreement is expected to be completed and filed with the GPSC for certification
during 1995.
In 1994, work force reduction programs were implemented, reducing earnings
by $55 million. These reductions will assist in efforts to control growth in
future operating expenses.
As discussed in Note 4 to the financial statements, regulatory uncertainties
exist related to the Rocky Mountain pumped storage hydroelectric project. In the
event the GPSC does not allow full recovery of the project's costs, then the
portion not allowed may have to be written off. The Company's total investment
in the project at completion is estimated to be approximately $200 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 and litigation currently pending in the U. S. Tax Court.
The Company has completed three in a series of four separate transactions to
sell Unit 4 of Plant Scherer to two Florida utilities. The remaining transaction
is scheduled to take place in 1995. If the sale takes place as planned, the
Company would realize an additional after-tax gain estimated to total
approximately $12 million. This transaction coincides with scheduled reductions
in capacity revenues from Florida utilities under contractual unit power sales
contracts of approximately $18 million in 1995 and an additional $10 million in
1996. Additionally, the expiration in 1994 of the contract for the sale of
long-term non-firm power to Florida Power Corporation will result in a $9
million decrease in capacity revenues in 1995. See Notes 5 and 6 to the
financial statements for additional information.
During 1994, Oglethorpe Power Corporation (OPC) gave the Company notice of
its intent to decrease its purchases of capacity under a power supply agreement.
As a result, the Company's capacity revenues from OPC will decline approximately
$8 million in 1996 and an additional $16 million in 1997.
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 Clean Air 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 may enhance the
incentive for IPPs to build cogeneration plants for a utility's large industrial
and commercial customers and sell excess energy generation to other utilities.
Although the Energy Act does not require transmission access to retail
customers, retail wheeling initiatives are rapidly evolving and becoming very
prominent issues in several states. 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
<PAGE>
7
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 1994 Annual Report
connected load may choose their electricity supplier. In addition, the bulk
power market has become very competitive as utilities, IPPs and cogenerators
seek to supply future capacity needs. Competition can create new business
opportunities, but it increases risk and has the potential to adversely affect
earnings.
The Federal Energy Regulatory Commission (FERC) regulates wholesale rate
schedules and power sales contracts that the Company has with its sales for
resale customers. The FERC currently is reviewing the rate of return on common
equity included in these schedules and contracts and may require such returns to
be lowered, possibly retroactively. See Note 3 to the financial statements under
"FERC Review of Equity Returns" for additional information.
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. 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 nuclear decommissioning. If current electric utility
industry accounting practices for decommissioning are changed: (1) annual
provisions for decommissioning could increase, and (2) the estimated cost for
decommissioning may be required to be recorded as a liability in the Balance
Sheets. In management's opinion -- should these changes be required -- the
changes would not have a significant adverse effect on results of operations
because of the Company's current and expected future ability to recover
decommissioning costs through rates. See Note 1 to the financial statements
under "Depreciation and Nuclear Decommissioning" for additional information.
FINANCIAL CONDITION
Overview
The principal changes in the Company's financial condition in 1994 were gross
utility plant additions of $638 million and the lowering of the cost of capital
achieved through the refinancing or retirement of $654 million 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 1994, the Company continued to lower its financing costs by refinancing
higher-cost issues. New issues during 1992 through 1994 totaled $3.5 billion and
retirement or repayment of securities totaled $4.1 billion. The retirements
included the redemption of $133 million and $253 million in 1994 and 1993,
respectively, of first mortgage bonds with the proceeds from the Plant Scherer
Unit 4 sales. Composite financing rates for the years 1992 through 1994, as of
year-end, were as follows:
==============================================================
1994 1993 1992
----------------------------------
Composite interest rate
on long-term debt 7.14% 7.86% 8.49%
Composite preferred
stock dividend rate 7.11% 6.76% 7.52%
==============================================================
The Company's current securities ratings are as follows:
==============================================================
Duff & Standard &
Phelps Moody's Poor's
First Mortgage Bonds A+ A2 A
Preferred Stock A- a3 A-
Unsecured Bonds A A3 A-
Commercial Paper D1 P1 A1
==============================================================
Liquidity and Capital Requirements
Cash provided from operations decreased by $128 million in 1994, primarily due
to lower retail sales, higher tax payments, and the receipt in 1993 of cash
payments from Gulf States as partial settlement of litigation.
<PAGE>
8
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 1994 Annual Report
The Company estimates that construction expenditures for the years 1995
through 1997 will total $579 million, $626 million and $724 million,
respectively. The Company will continue to invest in transmission and
distribution facilities and enhance existing generating plants. These
expenditures also include amounts for five combustion turbine generating units
and equipment that will be required to comply with the provisions of the Clean
Air Act.
The Company's annual contractual capacity purchases will decline by $70
million over the next three years. Cash requirements for sinking fund
requirements, redemptions announced, and maturities of long-term debt are
expected to total $360 million during 1995 through 1997.
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 1995 through 1997, the amount to be funded totals $16
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 $33 million as of December 31, 1994. 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 $709 million of unused credit
arrangements with banks at the beginning of 1995. See Note 8 to the financial
statements for additional information.
Completing the remaining transaction for the sale of Plant Scherer Unit 4
will generate approximately $131 million in 1995.
Georgia Power Capital, a limited partnership, was formed on November 10,
1994, for the purpose of issuing preferred securities and subsequently lending
the proceeds to the Company. In December 1994, Georgia Power Capital issued four
million shares of preferred securities at 9 percent and subsequently loaned the
proceeds of $100 million to the Company. This subordinated debt of the Company
is due December 19, 2024.
The Company is required to meet certain coverage requirements specified in
its mortgage indenture and corporate charter to issue new first mortgage bonds
and preferred stock. The Company's ability to satisfy all coverage requirements
is such that it could issue new first mortgage bonds and preferred stock to
provide sufficient funds for all anticipated requirements.
Environmental Issues
In November 1990, the Clean Air Act was signed into law. Title IV of the Clean
Air Act -- the acid rain compliance provision of the law -- will have a
significant impact on The Southern Company. Specific reductions in sulfur
dioxide and nitrogen oxide emissions from fossil-fired generating plants will be
required in two phases. Phase I compliance began in 1995 and affected eight
generating plants -- some 10,000 megawatts of capacity or 35 percent of total
capacity -- in the Southern electric system. Phase II compliance is required in
2000, and all fossil-fired generating plants in the Southern electric system
will be affected.
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
<PAGE>
9
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 1994 Annual Report
designed to use allowances as a compliance option.
The Southern Company expects to achieve Phase I sulfur dioxide compliance at
the eight affected plants by switching to low-sulfur coal, which has required
some equipment upgrades. This compliance strategy is expected to result in
unused emission allowances being banked for later use. Additional construction
expenditures were required to install equipment for the control of nitrogen
oxide emissions at these eight plants. Also, continuous emissions monitoring
equipment will be installed on all fossil-fired units. Under this Phase I
compliance approach, Georgia Power's construction expenditures are estimated to
total approximately $175 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
$20 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 2 percent in Georgia Power's annual revenue
requirements from customers could be necessary to fully recover the cost of
compliance for both Phase I and Phase II of 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.
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 has issued
rules for the application of reasonably available control technology to reduce
nitrogen oxide emissions by May 31, 1995. The results of these new rules require
nitrogen oxide controls, above Title IV requirements, on some of the Company's
plants. Final attainment rules, based on modeling studies, could require
installation of additional controls for nitrogen oxide emissions to meet the
1999 deadline. A decision on new requirements is expected in 1996. 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 by November 1995. 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 continues to evaluate the need for a new short-term ambient air
quality standard for sulfur dioxide. Preliminary results from an EPA study on
the impact of a new standard indicate that a number of plants could be required
to install sulfur dioxide controls. These controls would be in addition to the
controls already required to meet the acid rain provision of the Clean Air Act.
The EPA issued proposed rules in November 1994 and is required to take final
action on this issue in 1996. The impact of any new standard will depend on the
level chosen for the standard and cannot be determined at this time.
In addition, the EPA is evaluating the need to revise the ambient air
quality standards for particulate matter, nitrogen oxides, and ozone. The impact
of any new standard will depend on the level chosen for the standard and cannot
be determined at this time.
In 1995, 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.
<PAGE>
10
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 1994 Annual Report
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, $32
million, and $3 million in 1994, 1993, and 1992, respectively. Additional sites
may require environmental remediation for which the Company may be liable for a
portion or all required cleanup costs. See Note 4 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 another environmental matter.
Several major pieces of environmental legislation are being considered for
reauthorization or amendment by Congress. These include: the Clean Water Act;
the Comprehensive Environmental Response, Compensation, and Liability Act; the
Resource Conservation and Recovery 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 new legislation related to global climate change,
electromagnetic fields and other environmental and health concerns could
significantly affect the Company. The impact of new legislation -- if any --
will depend on the subsequent development and implementation of applicable
regulations. In addition, the potential exists for liability as the result of
lawsuits alleging damages caused by electromagnetic fields.
<PAGE>
11
<TABLE>
<CAPTION>
STATEMENTS OF INCOME
For the Years Ended December 31, 1994, 1993, and 1992
Georgia Power Company 1994 Annual Report
==================================================================================================
1994 1993 1992
- --------------------------------------------------------------------------------------------------
(in thousands)
<S> <C> <C> <C>
Operating Revenues:
Revenues (Note 1) $4,101,504 $4,389,513 $4,229,601
Revenues from affiliates 60,899 61,668 67,835
- --------------------------------------------------------------------------------------------------
Total operating revenues 4,162,403 4,451,181 4,297,436
- --------------------------------------------------------------------------------------------------
Operating Expenses:
Operation --
Fuel 870,653 951,507 929,780
Purchased power from non-affiliates 193,130 313,170 436,761
Purchased power from affiliates 158,063 194,024 158,306
Provision for separation benefits 82,238 - 9,778
Other 643,375 675,284 611,134
Maintenance 272,818 284,521 264,757
Depreciation and amortization 379,158 379,425 375,460
Amortization of deferred Plant Vogtle expenses, net (Note 3) 74,888 36,284 (30,804)
Taxes other than income taxes 194,566 192,671 179,460
Federal and state income taxes 399,413 452,122 377,542
- --------------------------------------------------------------------------------------------------
Total operating expenses 3,268,302 3,479,008 3,312,174
- --------------------------------------------------------------------------------------------------
Operating Income 894,101 972,173 985,262
Other Income (Expense):
Allowance for equity funds used during construction 5,663 3,168 5,855
Equity in earnings of unconsolidated subsidiary (Note 5) 3,588 4,127 4,635
Interest income 3,254 3,806 12,475
Other, net 10,626 11,902 (30,527)
Income taxes applicable to other income 7,975 37,661 25,163
- --------------------------------------------------------------------------------------------------
Income Before Interest Charges 925,207 1,032,837 1,002,863
- --------------------------------------------------------------------------------------------------
Interest Charges:
Interest on long-term debt 306,473 343,634 402,541
Allowance for debt funds used during construction (11,571) (8,271) (8,310)
Interest on interim obligations 17,529 15,530 9,694
Amortization of debt discount, premium, and expense, net 15,743 14,024 8,033
Other interest charges 23,483 47,393 12,425
- --------------------------------------------------------------------------------------------------
Net interest charges 351,657 412,310 424,383
- --------------------------------------------------------------------------------------------------
Net Income 573,550 620,527 578,480
Dividends on Preferred Stock 48,006 50,674 57,942
- --------------------------------------------------------------------------------------------------
Net Income After Dividends on Preferred Stock $ 525,544 $ 569,853 $ 520,538
==================================================================================================
The accompanying notes are an integral part of these statements.
</TABLE>
<PAGE>
12
<TABLE>
<CAPTION>
STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 1994, 1993, and 1992
Georgia Power Company 1994 Annual Report
==================================================================================================
1994 1993 1992
- --------------------------------------------------------------------------------------------------
(in thousands)
<S> <C> <C> <C>
Operating Activities:
Net income $ 573,550 $ 620,527 $ 578,480
Adjustments to reconcile net income to net
cash provided by operating activities --
Depreciation and amortization 484,032 475,152 471,014
Deferred income taxes and investment tax credits, net 33,567 150,735 189,251
Allowance for equity funds used during construction (5,663) (3,168) (5,855)
Deferred Plant Vogtle costs 74,888 36,284 (30,804)
Provision for separation benefits 68,599 - -
Gain on asset sales (22,717) (35,514) (12)
Other, net (72,597) (10,713) (14,738)
Changes in certain current assets and liabilities --
Receivables, net 67,218 27,088 (31,348)
Inventories (63,545) 82,433 (65,621)
Payables 5,409 17,364 25,303
Taxes accrued (60,474) 15,377 (22,828)
Energy cost recovery, retail 55,505 (74,260) (46,615)
Other (706) (35,691) (16,518)
- ------------------------------------------------------------------------------------------------
Net cash provided from operating activities 1,137,066 1,265,614 1,029,709
- ------------------------------------------------------------------------------------------------
Investing Activities:
Gross property additions (638,426) (674,432) (508,444)
Sales of property 132,644 261,687 46
Other (41,273) (43,154) 42,892
- ------------------------------------------------------------------------------------------------
Net cash used for investing activities (547,055) (455,899) (465,506)
- ------------------------------------------------------------------------------------------------
Financing Activities and Capital Contributions:
Proceeds:
Preferred securities of subsidiary 100,000 - -
Preferred stock - 175,000 195,000
First mortgage bonds - 1,135,000 975,000
Pollution control bonds 527,210 145,425 161,955
Long-term notes - 37,000 -
Retirements:
Preferred stock - (245,005) (165,004)
First mortgage bonds (133,559) (1,337,822) (1,381,300)
Pollution control bonds (510,320) (145,465) (160,205)
Other long-term debt (10,187) (19,451) (567)
Interim obligations, net (57,425) (51,444) 334,671
Payment of preferred stock dividends (47,147) (53,123) (60,475)
Payment of common stock dividends (429,300) (402,400) (384,000)
Miscellaneous (22,640) (63,648) (70,986)
- ------------------------------------------------------------------------------------------------
Net cash used for financing activities (583,368) (825,933) (555,911)
- ------------------------------------------------------------------------------------------------
Net Change in Cash and Cash Equivalents 6,643 (16,218) 8,292
Cash and Cash Equivalents at Beginning of Year 5,896 22,114 13,822
- ------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of Year $ 12,539 $ 5,896 $ 22,114
================================================================================================
Supplemental Cash Flow Information:
Cash paid during the year for --
Interest (net of amount capitalized) $ 336,155 $ 420,107 $ 435,203
Income taxes 386,653 275,867 190,674
- ------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these statements.
</TABLE>
<PAGE>
13
<TABLE>
<CAPTION>
BALANCE SHEETS
At December 31, 1994 and 1993
Georgia Power Company 1994 Annual Report
===========================================================================================
ASSETS 1994 1993
- -------------------------------------------------------------------------------------------
(in thousands)
<S> <C> <C>
Utility Plant:
Plant in service (Note 1) $ 14,054,917 $ 13,743,521
Less accumulated provision for depreciation 4,054,986 3,822,344
- -------------------------------------------------------------------------------------------
9,999,931 9,921,177
Nuclear fuel, at amortized cost (Note 1) 136,425 135,742
Construction work in progress (Note 4) 541,889 584,013
- -------------------------------------------------------------------------------------------
Total 10,678,245 10,640,932
- -------------------------------------------------------------------------------------------
Other Property and Investments:
Southern Electric Generating Company, at equity (Note 5) 26,985 29,201
Nuclear decommissioning trusts (Note 1) 54,297 37,937
Miscellaneous 89,542 31,941
- -------------------------------------------------------------------------------------------
Total 170,824 99,079
- -------------------------------------------------------------------------------------------
Current Assets:
Cash and cash equivalents 12,539 5,896
Receivables-
Customer accounts receivable 377,570 486,947
Other accounts and notes receivable 104,989 117,249
Affiliated companies 14,443 14,832
Accumulated provision for uncollectible accounts (4,500) (4,300)
Fossil fuel stock, at average cost 169,252 111,620
Materials and supplies, at average cost 293,464 287,551
Prepayments 55,383 65,269
Vacation pay deferred (Note 1) 40,823 41,575
- -------------------------------------------------------------------------------------------
Total 1,063,963 1,126,639
- -------------------------------------------------------------------------------------------
Deferred Charges:
Deferred charges related to income taxes (Note 7) 919,750 992,510
Deferred Plant Vogtle costs (Note 3) 432,092 506,980
Premium on reacquired debt, being amortized 164,676 153,146
Debt expense, being amortized 26,223 20,730
Miscellaneous 256,885 196,094
- -------------------------------------------------------------------------------------------
Total 1,799,626 1,869,460
- -------------------------------------------------------------------------------------------
Total Assets $ 13,712,658 $ 13,736,110
===========================================================================================
The accompanying notes are an integral part of these statements.
</TABLE>
<PAGE>
14
<TABLE>
<CAPTION>
BALANCE SHEETS
At December 31, 1994 and 1993
Georgia Power Company 1994 Annual Report
===========================================================================================
CAPITALIZATION AND LIABILITIES 1994 1993
- -------------------------------------------------------------------------------------------
(in thousands)
<S> <C> <C>
Capitalization (See accompanying statements):
Common stock equity $ 4,141,554 $ 4,045,458
Preferred stock 692,787 692,787
Preferred securities of subsidiary 100,000 -
Long-term debt 3,757,823 4,031,387
- -------------------------------------------------------------------------------------------
Total 8,692,164 8,769,632
- -------------------------------------------------------------------------------------------
Current Liabilities:
Long-term debt due within one year (Note 8) 167,420 10,543
Notes payable to banks (Note 8) 202,200 406,700
Commercial paper (Note 8) 222,602 75,527
Accounts payable-
Affiliated companies 41,760 38,115
Other 313,307 285,929
Customer deposits 47,017 45,922
Taxes accrued-
Federal and state income 2,856 31,639
Other 90,163 121,854
Interest accrued 110,256 110,497
Vacation pay accrued 39,720 40,060
Miscellaneous 70,006 64,527
- -------------------------------------------------------------------------------------------
Total 1,307,307 1,231,313
- -------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes (Note 7) 2,477,661 2,479,720
Accumulated deferred investment tax credits 453,121 478,334
Deferred credits related to income taxes (Note 7) 433,334 452,819
Disallowed Plant Vogtle capacity buyback costs (Note 5) 60,490 63,067
Miscellaneous 288,581 261,225
- -------------------------------------------------------------------------------------------
Total 3,713,187 3,735,165
- -------------------------------------------------------------------------------------------
Commitments and Contingent Matters (Notes 1, 2, 3, 4, 5, and 6)
Total Capitalization and Liabilities $ 13,712,658 $ 13,736,110
===========================================================================================
The accompanying notes are an integral part of these statements.
</TABLE>
<PAGE>
15
<TABLE>
<CAPTION>
STATEMENTS OF CAPITALIZATION
At December 31, 1994 and 1993
Georgia Power Company 1994 Annual Report
====================================================================================================
1994 1993 1994 1993
- ----------------------------------------------------------------------------------------------------
(in thousands) (percent of total)
<S> <C> <C> <C> <C>
Common Stock Equity:
Common stock, without par value --
Authorized -- 15,000,000 shares
Outstanding -- 7,761,500 shares $ 344,250 $ 344,250
Paid-in capital 2,384,348 2,384,348
Premium on preferred stock 413 413
Retained earnings (Note 8) 1,412,543 1,316,447
- ----------------------------------------------------------------------------------------------------
Total common stock equity 4,141,554 4,045,458 47.6 % 46.1 %
- ----------------------------------------------------------------------------------------------------
Cumulative Preferred Stock, without par value:
Authorized -- 55,000,000 shares in 1994 and 1993;
Outstanding -- 21,027,865 shares in 1994;
$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, 1995:
6.30% 100,000 100,000
6.86% 75,000 75,000
- ----------------------------------------------------------------------------------------------------
Total (annual dividend requirement -- $49,251,000) 692,787 692,787 8.0 7.9
- ----------------------------------------------------------------------------------------------------
Cumulative Preferred Securities of Subsidiary (Note 8):
$25 stated value -- 9% 100,000 -
- ----------------------------------------------------------------------------------------------------
Total (annual distribution requirement -- $9,000,000) 100,000 - 1.2 -
- ----------------------------------------------------------------------------------------------------
Long-Term Debt:
First mortgage bonds --
Maturity Interest Rates
-------- --------------
September 1, 1995 5 1/8% 130,000 130,000
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
2016 through 2019 9.23% to 10% 36,157 169,716
2022 through 2023 7.55% to 8 3/4% 660,000 660,000
2032 variable rates 200,000 200,000
- ----------------------------------------------------------------------------------------------------
Total first mortgage bonds 2,146,157 2,279,716
Pollution control obligations (Note 8) 1,678,140 1,661,250
Other long-term debt (Note 8) 124,686 135,058
Unamortized debt premium (discount), net (23,740) (34,094)
- ----------------------------------------------------------------------------------------------------
Total long-term debt (annual interest
requirement -- $282,112,000) 3,925,243 4,041,930
Less amount due within one year (Note 8) 167,420 10,543
- ----------------------------------------------------------------------------------------------------
Long-term debt excluding amount due within one year 3,757,823 4,031,387 43.2 46.0
- ----------------------------------------------------------------------------------------------------
Total Capitalization $ 8,692,164 $ 8,769,632 100.0 % 100.0 %
====================================================================================================
The accompanying notes are an integral part of these statements.
</TABLE>
<PAGE>
16
<TABLE>
<CAPTION>
STATEMENTS OF RETAINED EARNINGS
For the Years Ended December 31, 1994, 1993, and 1992
Georgia Power Company 1994 Annual Report
===============================================================================================
1994 1993 1992
- -----------------------------------------------------------------------------------------------
(in thousands)
<S> <C> <C> <C>
Balance at Beginning of Period $ 1,316,447 $ 1,159,380 $ 1,038,012
Net income after dividends on preferred stock 525,544 569,853 520,538
Cash dividends on common stock (429,300) (402,400) (384,000)
Preferred stock transactions, net (148) (10,386) (15,170)
- -----------------------------------------------------------------------------------------------
Balance at End of Period (Note 8) $ 1,412,543 $ 1,316,447 $ 1,159,380
===============================================================================================
STATEMENTS OF PAID-IN CAPITAL
For the Years Ended December 31, 1994, 1993, and 1992
Georgia Power Company 1994 Annual Report
===============================================================================================
1994 1993 1992
- -----------------------------------------------------------------------------------------------
(in thousands)
Balance at Beginning of Period $ 2,384,348 $ 2,384,140 $ 2,383,800
Contributions to capital by parent company - 208 340
- -----------------------------------------------------------------------------------------------
Balance at End of Period $ 2,384,348 $ 2,384,348 $ 2,384,140
===============================================================================================
The accompanying notes are an integral part of these financial statements.
</TABLE>
<PAGE>
17
NOTES TO FINANCIAL STATEMENTS
Georgia Power Company 1994 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), and
Southern Nuclear Operating Company (Southern Nuclear), and The Southern
Development and Investment Group (SDIG). The operating companies (Alabama Power
Company, Georgia Power Company, Gulf Power Company, Mississippi Power Company,
and Savannah Electric and Power Company) provide electric service in four
southeastern states. Intracompany contracts dealing with jointly owned
generating facilities, transmission lines and exchange of electric power are
regulated by the Federal Energy Regulatory Commission (FERC) or the Securities
and Exchange Commission. SCS provides, at cost, specialized services to The
Southern Company and each of the subsidiary companies. Southern Communications,
beginning in mid-1995, will provide digital wireless communications services to
The Southern Company's subsidiaries and also will market these services to the
public within the Southeast. Southern Electric designs, builds, owns, and
operates power production facilities and provides a broad range of technical
services to industrial companies and utilities in the United States and a number
of international markets. Southern Nuclear provides services to The Southern
Company's nuclear power plants. SDIG 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. Both The Southern Company and its
subsidiaries are subject to the regulatory provisions of this act. The Company
is also subject to regulation by the FERC and the Georgia Public Service
Commission (GPSC). The Company follows generally accepted accounting principles
and complies with the accounting policies and practices prescribed by the
respective regulatory commissions.
Certain prior years' data presented in the financial statements have been
reclassified to conform with current year presentation.
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:
===============================================================
1994 1993
--------------------
(in millions)
Deferred income taxes $ 920 $ 993
Deferred income tax credits (433) (453)
Deferred Plant Vogtle costs 432 507
Premium on reacquired debt 165 153
Demand-side program costs 97 49
Corporate building lease 48 47
Postretirement benefits 41 22
Vacation pay 41 42
Inventory conversions (39) (47)
Department of Energy assessments 36 41
Other, net 52 61
- ---------------------------------------------------------------
Total $1,360 $1,415
===============================================================
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 to their fair value.
<PAGE>
18
NOTES (continued)
Georgia Power Company 1994 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. Fuel costs were under recovered by $23 million and $79 million at
December 31, 1994, and 1993, respectively. These amounts are included in
customer accounts receivable on the Balance Sheets. The fuel cost recovery rate
was increased effective December 6, 1993.
The Company has a diversified base of customers. No single customer or
industry comprises 10 percent or more of revenues. In 1994, 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 $87
million in 1994, $75 million in 1993, and $84 million in 1992. 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 to
be approximately $33 million. This obligation is recognized in the accompanying
Balance Sheets and is being recovered through the fuel cost recovery provisions.
Depreciation and Nuclear Decommissioning
Depreciation of the original cost of depreciable utility plant in service is
provided primarily by using composite straight-line rates, which approximated
3.1 percent in 1994, 1993, and 1992. 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.
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.
<PAGE>
19
NOTES (continued)
Georgia Power Company 1994 Annual Report
Site study cost is the estimate to decommission the facility as of the site
study year, and ultimate cost is the estimate to decommission the facility as of
retirement date. The estimated costs of decommissioning -- both site study costs
and ultimate costs at December 31, 1994, -- 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
- -----------------------------------------------------------
Site study costs: (in millions)
Radiated structures $241 $193
Non-radiated structures 34 43
Other 60 49
- -----------------------------------------------------------
Total $335 $285
===========================================================
Ultimate costs: (in millions)
Radiated structures $641 $ 843
Non-radiated structures 91 190
Other 160 215
- -----------------------------------------------------------
Total $892 $1,248
===========================================================
(in millions)
Amount expensed in 1994 $6 $6
Accumulated provisions:
Balance in external trust funds $33 $22
Balance in internal reserves 29 10
- -----------------------------------------------------------
Total $62 $32
===========================================================
Assumed in ultimate costs:
Inflation rate 4.4% 4.4%
Trust earning 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
approved for ratemaking are $184 million for Plant Hatch and $155 million for
Plant Vogtle. These amounts are based on costs to decommission the radioactive
portions of the plants based on 1990 site studies. The estimated ultimate costs
based on the 1990 studies were $872 million and $1.4 billion for plants Hatch
and Vogtle, respectively. 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 assumed date of decommissioning,
changes in regulatory requirements, changes in technology, and changes in costs
of labor, materials, and equipment.
Plant Vogtle Phase-In Plans
In 1987 and 1989, the GPSC ordered that the allowed costs of Plant Vogtle Units
1 and 2 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.
Income Taxes
The Company provides deferred income taxes for all significant income tax
temporary differences. Investment tax credits utilized are deferred and
amortized to income over the average lives of the related property.
Effective January 1, 1993, the Company adopted FASB Statement No. 109,
Accounting for Income Taxes. Statement No. 109 required, among other things,
conversion to the liability method of accounting for accumulated deferred income
taxes. See Note 7 for additional information about Statement No. 109.
<PAGE>
20
NOTES (continued)
Georgia Power Company 1994 Annual Report
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 1994, 1993 and 1992, the average AFUDC rates
were 6.18 percent, 4.96 percent and 7.16 percent, respectively. The reduction in
the average AFUDC rate in 1993 reflects the Company's greater use of lower cost
short-term debt. 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 1994, 1993 and 1992,
respectively.
Utility Plant
Utility plant is stated at original cost with the exception of Plant Vogtle,
which is stated at cost less regulatory disallowances. Original cost includes
materials; labor; appropriate administrative and general costs; payroll-related
costs such as taxes, pensions, and other benefits; and the 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 replacement of
property (exclusive of minor items of property) is charged to utility plant.
The Company's investment in generating plant, based on its ownership
interests and net of the accumulated provision for depreciation, by type of
generation as of December 31 was as follows:
==================================================================
Nameplate
Type of Generation Net Investment Capacity
- -------------------- ----------------- ----------------
1994 1993 1994 1993
----------------- ----------------
(in millions) (megawatts)
Steam $1,674 $1,718 9,676 9,812
Nuclear 3,113 3,215 1,877 1,877
Hydro 335 338 862 862
Other 123 18 1,528 1,208
- -----------------------------------------------------------------
Total $5,245 $5,289 13,943 13,759
=================================================================
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:
=============================================================
Long-Term Debt
-------------------------
Carrying Fair
Amount Value
------------------------
Year (in millions)
1994 $3,838 $3,697
1993 3,954 4,197
The fair values for long-term debt 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.
Vacation Pay
Company employees earn vacation in one year and take it in the subsequent year.
However, for ratemaking purposes, vacation pay is recognized as an allowable
expense only when paid. Consistent with this ratemaking treatment, the Company
accrues a current liability for earned vacation pay and records a current
regulatory asset representing the future recoverability of this cost. This
amount was $41 million at December 31, 1994, and $42 million at December 31,
1993. In 1995, approximately 70 percent of the 1994 deferred vacation costs will
be expensed, and the balance will be charged to construction and other accounts.
<PAGE>
21
NOTES (continued)
Georgia Power Company 1994 Annual Report
2. RETIREMENT BENEFITS
Pension Plan
The Company has a defined benefit, trusteed,
non-contributory pension plan covering substantially all regular employees.
Benefits are based on the greater of amounts resulting from two different
formulas: years of service and final average pay or years of service and a flat
dollar benefit. The Company uses the "entry age normal method with a frozen
initial liability" actuarial method for funding purposes, subject to limitations
under federal income tax regulations. Amounts funded to the pension 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
FERC. During 1994, the Company funded $22 million to the qualified trusts.
Amounts funded are primarily invested in debt and equity securities.
Effective January 1, 1993, the Company adopted FASB Statement No. 106,
Employers' Accounting for Postretirement Benefits Other Than Pensions, on a
prospective basis. Statement No. 106 requires that medical care and life
insurance benefits for retired employees be accounted for on an accrual basis
using a specified actuarial method, "benefit/years-of-service."
In October 1993, the GPSC ordered the Company to phase in the adoption of
Statement No. 106 to cost of service over a five-year period, whereby one-fifth
of the additional expense was recognized in 1993 and the remaining additional
expense was deferred. An additional one-fifth of the costs will be expensed each
succeeding year until the costs are fully reflected in cost of service in 1997.
The cost deferred during the five-year period will be amortized to expense over
a 15-year period beginning in 1998. As a result of the regulatory treatment
allowed by the GPSC, the adoption of Statement No. 106 did not have a material
impact on net income.
Prior to 1993, the Company recognized these costs on a cash basis as
payments were made. The total costs of such benefits recognized by the Company
in 1992 were $13 million.
Funded Status and Cost of Benefits
Shown in the following tables are actuarial results and assumptions for pension
and postretirement medical and life insurance benefits as computed under the
requirements of Statement Nos. 87 and 106, respectively. The funded status of
the plans at December 31 was as follows:
Pension
===============================================================
1994 1993
---------------------
Actuarial present value of (in millions)
benefit obligations:
Vested benefits $ 689 $ 655
Non-vested benefits 32 35
- ---------------------------------------------------------------
Accumulated benefit obligation 721 690
Additional amounts related
to projected salary increases 294 257
- ---------------------------------------------------------------
Projected benefit obligation 1,015 947
Less:
Fair value of plan assets 1,419 1,495
Unrecognized net gain (371) (490)
Unrecognized prior service cost 28 31
Unrecognized transition asset (58) (62)
- ---------------------------------------------------------------
Prepaid asset recognized in
the Balance Sheets $ 3 $ 27
===============================================================
<PAGE>
22
NOTES (continued)
Georgia Power Company 1994 Annual Report
Postretirement Medical
===============================================================
1994 1993
--------------------
(in millions)
Actuarial present value of
benefit obligation:
Retirees and dependents $168 $136
Employees eligible to retire 7 12
Other employees 191 206
- ---------------------------------------------------------------
Accumulated benefit obligation 366 354
Less:
Fair value of plan assets 46 30
Unrecognized net loss 7 40
Unrecognized transition
obligation 236 251
- ---------------------------------------------------------------
Accrued liability recognized in the
Balance Sheets $ 77 $ 33
===============================================================
Postretirement Life
===============================================================
1994 1993
---------------
(in millions)
Actuarial present value of benefit obligation:
Retirees and dependents $35 $32
Employees eligible to retire - -
Other employees 38 40
- ---------------------------------------------------------------
Accumulated benefit obligation 73 72
Less:
Fair value of plan assets 6 1
Unrecognized net gain (8) (6)
Unrecognized transition
obligation 65 69
- ---------------------------------------------------------------
Accrued liability recognized in the
Balance Sheets $10 $ 8
===============================================================
Weighted average rates used in actuarial calculations:
=============================================================
1994 1993 1992
------------------------------
Discount 8.0% 7.5% 8.0%
Annual salary increase 5.5 5.0 6.0
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 10.5 percent for 1994, decreasing gradually to 6 percent through the year
2000 and remaining at that level thereafter. An annual increase in the assumed
medical care cost trend rate of 1.0 percent would increase the accumulated
medical benefit obligation as of December 31, 1994, by $68 million and the
aggregate of the service and interest cost components of the net retiree medical
cost by $10 million.
The components of the plans' net costs are shown below:
Pension
==============================================================================
1994 1993 1992
----------------------------
(in millions)
Benefits earned during the year $ 34 $ 33 $ 34
Interest cost on projected
benefit obligation 71 69 65
Actual (return) loss on plan assets 35 (194) (61)
Net amortization and deferral (160) 84 (38)
- ------------------------------------------------------------------------------
Net pension cost $ (20) $ (8) $ -
==============================================================================
Net pension costs were negative in 1994 and 1993. Of net pension costs
recorded, $15 million in 1994 and $6 million in 1993, were recorded as a
reduction to operating expense, with the balance being recorded as a reduction
to construction and other accounts.
Postretirement Medical
===============================================================================
1994 1993
--------------
(in millions)
Benefits earned during the year $ 13 $ 11
Interest cost on accumulated
benefit obligation 27 23
Amortization of transition
obligation over 20 years 12 12
Actual (return) loss on plan assets 1 (4)
Net amortization and deferral (3) 2
- -------------------------------------------------------------------------------
Net postretirement cost $ 50 $ 44
===============================================================================
Postretirement Life
===============================================================================
1994 1993
-----------
(in millions)
Benefits earned during the year $ 2 $ 3
Interest cost on accumulated
benefit obligation 6 6
Amortization of transition
obligation over 20 years 3 3
Actual return on plan assets - -
Net amortization and deferral - -
- -------------------------------------------------------------------------------
Net postretirement cost $11 $12
===============================================================================
<PAGE>
23
NOTES (continued)
Georgia Power Company 1994 Annual Report
Of the above net postretirement medical and life insurance costs recorded in
1994, $28 million was charged to operating expenses, $18 million was deferred,
and the remainder was charged to construction and other accounts. In 1993, $21
million was charged to operating expenses, $21 million was 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 the Company's programs were $82 million and $10 million for the
years 1994 and 1992, respectively. Additionally, in 1994, the Company recognized
$8 million for its share of costs associated with SCS's work force reduction
program.
3. LITIGATION AND REGULATORY MATTERS
Demand-Side Conservation Programs
In October 1993, a Superior Court of Fulton County, Georgia, judge ruled that
rate riders previously approved by the GPSC for recovery of the Company's costs
incurred in connection with demand-side conservation programs were unlawful. The
judge held that the GPSC lacked statutory authority to approve such rate riders
except through general rate case proceedings and that those procedures had not
been followed. The Company suspended collection of the demand-side conservation
costs and appealed the court's decision to the Georgia Court of Appeals. In
December 1993, the GPSC approved the Company's request for an accounting order
allowing the Company to defer all current unrecovered and future costs related
to these programs until the superior court's decision is reversed or until the
next general rate case proceedings. An association of industrial customers filed
a petition for review of the accounting order in superior court.
In July 1994, the Georgia Court of Appeals upheld the legality of the rate
riders. In November 1994, the Supreme Court of Georgia denied petitions for
review of this ruling. As a result, the Company resumed collection under the
rate riders in December 1994. In February 1995, the GPSC initiated a true-up
proceeding to review program costs which have been incurred by the Company and
costs expected to be incurred during 1995 in order to adjust the rate riders
accordingly. The proceeding will also address a plan for recovery of costs
deferred under the accounting order. The Company's costs related to these
conservation programs through 1994 were $115 million, of which $18 million has
been collected and the remainder deferred.
The final outcome of this matter cannot now be determined; however, in
management's opinion, the final outcome will not have a material adverse effect
on the Company's financial statements.
Tax Litigation
In June 1994, a tax deficiency notice was received from the Internal Revenue
Service (IRS) for the years 1984 through 1987 with regard to the tax accounting
by the Company for the sale in 1984 of an interest in Plant Vogtle and related
capacity and energy buyback commitments. The potential tax deficiency and
interest arising from this issue currently amount to $28 million and $32
million, respectively. The tax deficiency relates to a timing issue as to when
taxes are paid; therefore, only the interest portion could affect future income.
Management believes that the IRS position is incorrect, and the Company has
filed a petition with the U. S. Tax Court challenging the IRS position. In order
to minimize additional interest charges should the IRS's position prevail, the
Company made a payment to the IRS related to the potential tax deficiency for
the years 1984 through 1987 in September 1994.
The final outcome of this matter cannot now be determined; however, in
management's opinion, the final outcome will not have a material adverse effect
on the Company's financial statements.
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.
<PAGE>
24
NOTES (continued)
Georgia Power Company 1994 Annual Report
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 is scheduled to continue
until January 1996.
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 $35
million at December 31, 1994. Although the final outcome of this matter cannot
now be determined, in management's opinion, the final outcome will not result in
changes that would have a material adverse effect on the Company's financial
statements.
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 such request is pending before the FERC. 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.
While the outcome of this matter cannot be determined, in management's
opinion, it will not have a material adverse effect on the Company's financial
statements.
Plant Vogtle Phase-In Plans
Pursuant to orders from the GPSC, the Company recorded a deferred return under
phase-in plans for Plant Vogtle Units 1 and 2 until October 1991 when the
allowed investment was fully reflected in rates. In addition, the GPSC issued
two separate accounting orders that required the Company to defer substantially
all operating and financing costs related to both units until rate orders
addressed these costs. These GPSC orders provide for the recovery of deferred
costs within 10 years. The GPSC modified the phase-in plans in 1991 to
accelerate the recognition of costs previously deferred under the Plant Vogtle
Unit 2 phase-in plan and to levelize the remaining Plant Vogtle declining
capacity buyback expenses.
Under these orders, the Company has deferred and amortized these costs (as
recovered through rates) as follows:
=============================================================
1994 1993 1992
---------------------------
(in millions)
Deferred costs at beginning
of year $507 $383 $375
- --------------------------------------------------------------
Deferred capacity buyback
expenses 10 38 100
Amortization of previously
deferred costs (85) (74) (69)
Less income taxes - - (23)
- --------------------------------------------------------------
Net (amortization) deferral (75) (36) 8
- --------------------------------------------------------------
Effect of adoption of FASB
Statement No. 109 - 160 -
- --------------------------------------------------------------
Deferred costs at end of year $432 $507 $383
==============================================================
<PAGE>
25
NOTES (continued)
Georgia Power Company 1994 Annual Report
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
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, 1994,
the remaining amount to be collected was $5 million.
4. COMMITMENTS AND CONTINGENCIES
Rocky Mountain Project Status
In its 1985 financing order, the GPSC concluded that completion of the Rocky
Mountain pumped storage hydroelectric project in 1991 as then planned was not
economically justifiable and reasonable and withheld authorization for the
Company to spend funds from approved securities issuances on that project. In
1988, the Company and OPC entered into a joint ownership agreement for OPC to
assume responsibility for the construction and operation of the project, as
discussed in Note 5. However, full recovery of the Company's costs depends on
the GPSC's treatment of the project's costs and disposition of the project's
capacity output. In the event the GPSC does not allow full recovery of the
project's costs, then the portion not allowed may have to be written off. AFUDC
accrued on the Rocky Mountain project has not been credited to income or
included in the project cost since December 1985. If accrual of AFUDC is not
resumed, the Company's estimated total investment in the project at completion
would be approximately $200 million. The plant is scheduled to begin commercial
operation in 1995.
The ultimate outcome of this matter cannot now be determined.
Construction Program
While the Company has no new baseload generating plants under construction,
the construction of five combustion turbine peaking units is planned to be
completed by 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 $579 million in 1995, $626 million in 1996 and
$724 million in 1997. These estimated additions include AFUDC of $27 million in
1995, $17 million in 1996, and $22 million in 1997. The estimates for property
additions for the three-year period include $92 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 commitments were approximately $4.6 billion at
December 31, 1994. Additional commitments for coal and for nuclear fuel will be
required in the future to supply the Company's fuel needs.
<PAGE>
26
NOTES (continued)
Georgia Power Company 1994 Annual Report
Operating Leases
The Company has entered into coal rail car rental agreements with various terms
and expiration dates. These expenses totaled $13 million, $8 million, and $7
million for 1994, 1993, and 1992, respectively. At December 31, 1994, estimated
minimum rental commitments for noncancelable operating leases were as follows:
======================================================
Amounts
--------------
Year (in millions)
- ----
1995 $ 12
1996 11
1997 10
1998 10
1999 10
2000 and thereafter 136
- ------------------------------------------------------
Total minimum payments $189
======================================================
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. 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. In management's
opinion, however, based upon the nature and extent of the Company's activities
relating to the site, the final outcome will not have a material adverse effect
on the Company's financial statements.
In compliance with the recently enacted Georgia Hazardous Site Response Act,
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 $4 million in expenses
for the anticipated clean-up cost for two sites that the Company plans 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 $3 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 sites were required to be remediated, the Company could incur
expenses of up to approximately $25 million in additional clean-up costs, and
construction expenditures of up to $100 million to develop new waste management
facilities or install additional pollution control devices.
The final outcome of this matter cannot now be determined; however, in
management's opinion, the final outcome will not have a material adverse effect
on the Company's financial statements.
Nuclear Insurance
Under the Price-Anderson Amendments Act of 1988, the Company maintains
agreements of indemnity with the NRC that, together with private insurance,
cover third-party liability arising from any nuclear incident occurring at the
Company's nuclear power plants. The act provides funds up to $8.9 billion for
public liability claims that could arise from a single nuclear incident. Each
nuclear plant is insured against this liability to a maximum of $200 million by
private insurance, with the remaining coverage provided by a mandatory program
of deferred premiums that could be assessed, after a nuclear incident, against
all owners of nuclear reactors. A company could be assessed up to $79 million
per incident for each licensed reactor it operates but not more than an
aggregate of $10 million per incident to be paid in a calendar year for each
reactor. Such maximum assessment for the Company -- based on its ownership and
buyback interests -- is $163 million per incident but not more than an aggregate
of $21 million to be paid for each incident in any one year.
<PAGE>
27
NOTES (continued)
Georgia Power Company 1994 Annual Report
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 $15 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 $25 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.
5. FACILITY SALES AND JOINT OWNERSHIP AGREEMENTS
Since 1975, the Company has sold undivided interests in plants Hatch, Wansley,
Vogtle, and Scherer Units 1 and 2, together with transmission facilities, to
OPC, an electric membership generation and transmission corporation; MEAG, a
public corporation and an instrumentality of the state of Georgia; and the City
of Dalton, Georgia. The Company has sold an interest in Plant Scherer Unit 3 to
Gulf Power, an affiliate.
Additionally, the Company has completed three of four separate transactions
to sell Unit 4 of Plant Scherer to Florida Power & Light Company (FPL) and
Jacksonville Electric Authority (JEA) for a total price of approximately $808
million, including any gains on these transactions. FPL will eventually own
approximately 76.4 percent of the unit, with JEA owning the remainder. Georgia
Power will continue to operate the unit.
The completed and scheduled remaining transactions are as follows:
=============================================================
Closing Percent After-Tax
Date Capacity Ownership Amount Gain
- -------------------------------------------------------------
(in megawatts) (in millions)
July 1991 290 35.46% $291 $14
June 1993 258 31.44 253 18
June 1994 135 16.55 133 11
June 1995 135 16.55 131 12
- -------------------------------------------------------------
Total 818 100.00% $808 $55
=============================================================
Except as otherwise noted, the Company has contracted to operate and
maintain all jointly owned facilities. The Company includes its proportionate
share of plant operating expenses in the corresponding operating expenses in the
Statements of Income.
As discussed in Note 4, the Company and OPC have a joint ownership
arrangement for the Rocky Mountain pumped storage hydroelectric project under
which the Company will retain its present investment in the project and OPC will
<PAGE>
28
NOTES (continued)
Georgia Power Company 1994 Annual Report
finance and complete the remainder of the project and operate the completed
facility. Based on current cost estimates the Company's ownership will be
approximately 25 percent of the project (194 megawatts of capacity) at
completion.
The Company will own six of eight 80 megawatt combustion turbine generating
units and 75 percent of the related common facilities being jointly constructed
at Plant McIntosh with Savannah Electric, an affiliate. The Company's investment
in the project at December 31, 1994, was $149 million and is expected to total
approximately $182 million when the project is completed. Four of the Company's
six units began commercial operation during 1994, and the remaining two units
are expected to be completed by June, 1995. Savannah Electric will operate these
units.
In 1994, the Company and FPC entered into a joint ownership agreement
regarding a 150 megawatt combustion turbine unit to be constructed near Orlando,
Florida. The unit is scheduled to be in commercial operation in early 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.
In connection with the joint ownership arrangements for plants Vogtle and
Scherer, the Company has made commitments to purchase declining fractions of
OPC's and MEAG's capacity and energy from these units. These commitments are in
effect during periods of up to 10 years following commercial operation (and with
regard to a portion of a 5 percent interest in Plant Vogtle owned by MEAG, until
the latter of the retirement of the plant or the latest stated maturity date of
MEAG's bonds issued to finance such ownership interest). The payments for
capacity are required whether or not any capacity is available. The energy cost
is a function of each unit's variable operating costs. Except as noted below,
the cost of such capacity and energy is included in purchased power from
non-affiliates in the Company's Statements of Income. Capacity payments totaled
$129 million, $183 million and $289 million in 1994, 1993 and 1992,
respectively. The Plant Scherer buyback agreements ended in 1993. The current
projected Plant Vogtle capacity payments for the next five years are as follows:
$77 million in 1995, $70 million in 1996, $59 million in 1997, $59 million in
1998, and $59 million in 1999. Portions of the payments noted above relate to
costs in excess of Plant Vogtle's allowed investment for ratemaking purposes.
The present value of these portions was written off in 1987 and 1990.
Additionally, the Plant Vogtle declining capacity buyback expense is being
levelized over a six-year period. See Note 3 for further information.
At December 31, 1994, 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
Unit 4 818 16.6
Plant McIntosh
Common Facilities N/A 75.0
(combustion-turbine)
=================================================================
Accumulated
Facility (Type) Investment Depreciation
- -----------------------------------------------------------------
(in millions)
Plant Vogtle (nuclear) $3,289* $628
Plant Hatch (nuclear) 842 346
Plant Wansley (coal) 287 129
Plant Scherer (coal)
Units 1 and 2 112 36
Unit 3 540 121
Unit 4 119 18
Plant McIntosh
Common Facilities
(combustion-turbine) 17 **
- -----------------------------------------------------------------
* Investment net of write-offs.
** Less than $1 million.
<PAGE>
29
NOTES (continued)
Georgia Power Company 1994 Annual Report
The Company and an affiliate, Alabama Power, own equally all of the
outstanding capital stock of Southern Electric Generating Company (SEGCO), which
owns electric generating units with a total rated capacity of 1,020 megawatts,
as well as associated transmission facilities. The capacity of the units has
been sold equally to the Company and Alabama Power under a contract 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:
============================================================
1994 1993 1992
- ------------------------------------------------------------
(in millions)
Energy $43 $60 $47
Capacity 33 30 28
- ------------------------------------------------------------
Total $76 $90 $75
============================================================
Kilowatt-hours 2,429 3,352 2,664
- ------------------------------------------------------------
At December 31, 1994, 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.
6. LONG-TERM POWER SALES AGREEMENTS
The Company and the operating affiliates of The Southern Company have entered
into long-term contractual agreements for the sale of capacity and energy to
non-affiliated utilities located outside the system's service territory. These
agreements consist of firm unit power sales pertaining to capacity from specific
generating units and non-firm sales 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)
1994 $ 75 403 $ 9 101
1993 135 830 17 200
1992 223 1,363 10 124
Long-term non-firm power of 200 megawatts was sold by the Southern electric
system in 1994 to FPC, of which the Company's share was 101 megawatts, under a
contract that expired at year-end. Sales under these long-term non-firm power
sales agreements are made from available power pool energy, and the revenues
from the sales are shared by the operating affiliates.
Unit power from specific generating plants is being sold to FPL, JEA, and
the City of Tallahassee, Florida and beginning in 1994 to FPC. Under these
agreements, the Company sold approximately 403 megawatts of capacity in 1994 and
is scheduled to sell approximately 248 megawatts of capacity in 1995.
Thereafter, these sales will decline to an estimated 172 megawatts in 1996 then
will remain at an approximate level of 158 megawatts through 1999. After 2000,
capacity sales will decline to approximately 102 megawatts -- unless reduced by
FPL, FPC, and JEA -- until the expiration of the contracts in 2010.
<PAGE>
30
NOTES (continued)
Georgia Power Company 1994 Annual Report
7. 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, 1994, the tax-related regulatory assets were $920 million and
the tax-related regulatory liabilities were $433 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:
==============================================================
1994 1993 1992
---------------------------
Total provision for income taxes: (in millions)
Federal:
Currently payable $306 $223 $139
Deferred -
Current year 86 181 170
Reversal of prior years (57) (40) (6)
Deferred investment tax
credits (1) (18) (6)
- --------------------------------------------------------------
334 346 297
- --------------------------------------------------------------
State:
Currently payable 52 41 24
Deferred -
Current year 15 31 35
Reversal of prior years (10) (3) (3)
- --------------------------------------------------------------
57 69 56
- --------------------------------------------------------------
Total 391 415 353
- --------------------------------------------------------------
Less:
Income taxes charged
(credited) to other income (8) (37) (25)
- --------------------------------------------------------------
Federal and state income
taxes charged to operations $399 $452 $378
==============================================================
The tax effects of temporary differences between the carrying amounts of
assets and liabilities in the financial statements and their respective tax
basis, which give rise to deferred tax assets and liabilities are as follows:
===============================================================
1994 1993
-----------------
(in millions)
Deferred tax liabilities:
Accelerated depreciation $1,541 $1,458
Property basis differences 1,085 1,163
Deferred Plant Vogtle costs 141 161
Premium on reacquired debt 68 63
Deferred regulatory costs 48 24
Fuel clause underrecovered 9 32
Other 23 38
- ---------------------------------------------------------------
Total 2,915 2,939
- ---------------------------------------------------------------
Deferred tax assets:
Other property basis differences 250 263
Federal effect of state deferred taxes 94 92
Other deferred costs 79 61
Disallowed Plant Vogtle buybacks 26 29
Accrued interest 10 24
Other 13 12
- ---------------------------------------------------------------
Total 472 481
- ---------------------------------------------------------------
Net deferred tax liabilities 2,443 2,458
Portion included in current assets 35 22
- ---------------------------------------------------------------
Accumulated deferred income taxes
in the Balance Sheets $2,478 $2,480
===============================================================
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 $25 million in 1994, $19 million in 1993, and $19 million in 1992.
At December 31, 1994, all investment tax credits available to reduce federal
income taxes payable had been utilized.
<PAGE>
31
NOTES (continued)
Georgia Power Company 1994 Annual Report
A reconciliation of the federal statutory tax rate to the effective income
tax rate is as follows:
=============================================================
1994 1993 1992
------------------------
Federal statutory rate 35% 35% 34%
State income tax, net of
federal deduction 4 4 4
Non-deductible book
depreciation 3 3 3
Difference in prior years'
deferred and current tax rate (1) (1) (1)
Other - (1) (2)
- -------------------------------------------------------------
Effective income tax rate 41% 40% 38%
=============================================================
The Southern Company and its subsidiaries file a consolidated federal income
tax return. Under a joint consolidated income tax agreement, each company's
current and deferred tax expense is computed on a stand-alone basis, and
consolidated tax savings are allocated to each company based on its ratio of
taxable income to total consolidated taxable income.
8. CAPITALIZATION
Common Stock Dividend Restrictions
The Company's first mortgage bond indenture contains various common stock
dividend restrictions that remain in effect as long as the bonds are
outstanding. At December 31, 1994, $742 million of retained earnings were
restricted against the payment of cash dividends on common stock under terms of
the mortgage indenture. Supplemental indentures in connection with future first
mortgage bond issues may contain more stringent common stock dividend
restrictions than those currently in effect.
The Company's charter limits cash dividends on common stock to the lesser of
the retained earnings balance or 75 percent of net income available for such
stock during a prior period of 12 months if the ratio of common stock equity to
total capitalization, including retained earnings, adjusted to reflect the
payment of the proposed dividend, is below 25 percent, and to 50 percent of such
net income if such ratio is less than 20 percent. At December 31, 1994, the
ratio as defined was 47.3 percent.
Preferred Securities
Georgia Power Capital, a limited partnership, was formed November 10, 1994, for
the purpose of issuing preferred securities and subsequently lending the
proceeds to the Company. In December 1994, Georgia Power Capital issued four
million shares of preferred securities at 9 percent and subsequently loaned the
proceeds of $100 million to the Company. This subordinated debt of the Company
is due December 19, 2024.
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 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 $651 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 1994 1993
- ------------------------------------------------------------
(in millions)
2004 5.70% $ 39 $ 39
2005-2008 5.375% to 6.75% 59 59
2011-2014 11.75% & Variable 10 477
2015-2019 6.00% to 10.60%
& Variable 786 830
2021-2024 5.40% to 7.25% &
Variable 784 256
- ------------------------------------------------------------
Total pollution control bonds $1,678 $1,661
============================================================
Bank Credit Arrangements
At the beginning of 1995, the Company had unused credit arrangements with banks
totaling $709 million, of which $268 million expires at various times during
1995, $41 million expires at May 1, 1997, and $400 million expires at June 30,
1997.
<PAGE>
32
NOTES (continued)
Georgia Power Company 1994 Annual Report
The $400 million expiring June 30, 1997, is under revolving credit
arrangements with several banks providing the Company, Alabama Power, and The
Southern Company up to a total credit amount of $400 million. To provide
liquidity support for commercial paper programs and for other short-term cash
needs, $165 million and $135 million of the $400 million available credit are
currently dedicated for the Company and Alabama Power, respectively. However,
the allocations can be changed among the borrowers by notifying the respective
banks.
During the term of the agreements expiring in 1997, 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 $709 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, 1994, is
$219 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 1994.
Other Long-Term Debt
Assets acquired under capital leases are recorded in the Balance Sheets as
utility plant in service, and the related obligations are classified as
long-term debt. At December 31, 1994 and 1993, the Company had a capitalized
lease obligation for its corporate headquarters building of $88 million with an
interest rate of 8.1 percent. The maturity of this capital lease obligation
through 1999 is approximately as follows: $310 thousand in 1995, $336 thousand
in 1996, $365 thousand in 1997, $395 thousand in 1998, and $429 thousand in
1999.
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, 1994, and 1993, the interest and lease
amortization deferred on the Balance Sheets are $48 million and $47 million,
respectively.
In December 1993, the Company borrowed $37 million through a long-term note
due in 1995.
Assets Subject to Lien
The Company's mortgage dated as of March 1, 1941, as amended and supplemented,
securing the first mortgage bonds issued by the Company, constitutes a direct
lien on substantially all of the Company's fixed property and franchises.
Long-Term Debt Due Within One Year
The current portion of the Company's long-term debt is as follows:
================================================================
1994 1993
--------------
(in millions)
First mortgage bond maturity $130 $ -
Other long-term debt 37 11
- ----------------------------------------------------------------
Total $167 $11
================================================================
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 or reacquired bonds, or
by pledging additional property equal to 1 2/3 times the requirement. The 1994
requirement was funded in December 1993. The 1995 requirement of $23 million
<PAGE>
33
NOTES (continued)
Georgia Power Company 1994 Annual Report
will be satisfied 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.
9. QUARTERLY FINANCIAL DATA (UNAUDITED)
Summarized quarterly financial information for 1994 and 1993 is as follows:
==================================================================
Net Income
After
Dividends on
Operating Operating Preferred
Quarter Ended Revenues Income Stock
- ------------------------------------------------------------------
(in millions)
March 1994 $ 992 $157 $ 58
June 1994 1,030 227 140
September 1994 1,213 331 233
December 1994 927 179 95
March 1993 $1,004 $221 $108
June 1993 1,096 219 141
September 1993 1,376 356 245
December 1993 975 176 76
- ------------------------------------------------------------------
Earnings in 1994 declined by $55 million as a result of work force
reduction programs. Of this amount, $52 million was recorded in the first
quarter of 1994.
The Company's business is influenced by seasonal weather
conditions.
<PAGE>
34
<TABLE>
<CAPTION>
SELECTED FINANCIAL AND OPERATING DATA
Georgia Power Company 1994 Annual Report
===================================================================================================
1994 1993 1992
- ---------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Operating Revenues (in thousands) $4,162,403 $4,451,181 $4,297,436
Net Income after Dividends
on Preferred Stock (in thousands) $525,544 $569,853 $520,538
Cash Dividends on Common Stock (in thousands) $429,300 $402,400 $384,000
Return on Average Common Equity (percent) 12.84 14.37 13.60
Total Assets (in thousands) $13,712,658 $13,736,110 $10,964,442
Gross Property Additions (in thousands) $638,426 $674,432 $508,444
- ---------------------------------------------------------------------------------------------------
Capitalization (in thousands):
Common stock equity $4,141,554 $4,045,458 $3,888,237
Preferred stock 692,787 692,787 692,792
Preferred stock subject to mandatory redemption - - 6,250
Preferred securities of subsidiary 100,000 - -
Long-term debt 3,757,823 4,031,387 4,131,016
- ---------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) $8,692,164 $8,769,632 $8,718,295
===================================================================================================
Capitalization Ratios (percent):
Common stock equity 47.6 46.1 44.6
Preferred stock 8.0 7.9 8.0
Preferred securities of subsidiary 1.2 - -
Long-term debt 43.2 46.0 47.4
- ---------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) 100.0 100.0 100.0
===================================================================================================
First Mortgage Bonds (in thousands):
Issued - 1,135,000 975,000
Retired 133,559 1,337,822 1,381,300
Preferred Stock (in thousands):
Issued - 175,000 195,000
Retired - 245,005 165,004
Preferred Securities of subsidiary (in thousands):
Issued 100,000 - -
Retired - - -
- ---------------------------------------------------------------------------------------------------
Security Ratings:
First Mortgage Bonds -
Moody's A2 A3 A3
Standard and Poor's A A- A-
Duff & Phelps A+ A+ A-
Preferred Stock -
Moody's a3 baa1 baa1
Standard and Poor's A- BBB+ BBB+
Duff & Phelps A- A- BBB
- ---------------------------------------------------------------------------------------------------
Customers (year-end):
Residential 1,466,382 1,441,972 1,421,175
Commercial 193,648 188,820 183,784
Industrial 10,976 11,217 11,479
Other 2,426 2,322 2,269
- ---------------------------------------------------------------------------------------------------
Total 1,673,432 1,644,331 1,618,707
===================================================================================================
Employees (year-end) 11,765 12,528 12,600
</TABLE>
<PAGE>
35A
<TABLE>
<CAPTION>
SELECTED FINANCIAL AND OPERATING DATA
Georgia Power Company 1994 Annual Report
===================================================================================================
1991 1990 1989
- ---------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Operating Revenues (in thousands) $4,301,428 $4,445,809 $4,145,240
Net Income after Dividends
on Preferred Stock (in thousands) $474,855 $208,066 $449,099
Cash Dividends on Common Stock (in thousands) $375,200 $389,600 $394,500
Return on Average Common Equity (percent) 12.76 5.52 11.72
Total Assets (in thousands) $10,842,538 $11,176,619 $11,372,346
Gross Property Additions (in thousands) $548,051 $558,727 $727,631
- ---------------------------------------------------------------------------------------------------
Capitalization (in thousands):
Common stock equity $3,766,551 $3,673,913 $3,860,657
Preferred stock 607,796 607,796 607,844
Preferred stock subject to mandatory redemption 118,750 125,000 155,000
Preferred securities of subsidiary - - -
Long-term debt 4,553,189 5,000,225 5,054,001
- ---------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) $9,046,286 $9,406,934 $9,677,502
===================================================================================================
Capitalization Ratios (percent):
Common stock equity 41.7 39.1 39.9
Preferred stock 8.0 7.8 7.9
Preferred securities of subsidiary - - -
Long-term debt 50.3 53.1 52.2
- ---------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) 100.0 100.0 100.0
===================================================================================================
First Mortgage Bonds (in thousands):
Issued - 300,000 250,000
Retired 598,384 91,117 91,516
Preferred Stock (in thousands):
Issued 100,000 - -
Retired 100,000 83,750 7,500
Preferred Securities of subsidiary (in thousands):
Issued - - -
Retired - - -
- ---------------------------------------------------------------------------------------------------
Security Ratings:
First Mortgage Bonds -
Moody's Baa1 Baa1 Baa2
Standard and Poor's BBB+ BBB+ BBB+
Duff & Phelps BBB+ BBB BBB
Preferred Stock -
Moody's baa1 baa1 baa2
Standard and Poor's BBB BBB BBB
Duff & Phelps BBB- BBB- BBB-
- ---------------------------------------------------------------------------------------------------
Customers (year-end):
Residential 1,397,682 1,378,888 1,355,211
Commercial 179,933 178,391 177,814
Industrial 11,946 12,115 12,311
Other 2,190 2,114 2,050
- ---------------------------------------------------------------------------------------------------
Total 1,591,751 1,571,508 1,547,386
===================================================================================================
Employees (year-end) 13,700 13,746 13,900
</TABLE>
<PAGE>
35B
<TABLE>
<CAPTION>
SELECTED FINANCIAL AND OPERATING DATA
Georgia Power Company 1994 Annual Report
===================================================================================================
1988 1987 1986
- ---------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Operating Revenues (in thousands) $3,897,479 $3,786,485 $3,561,603
Net Income after Dividends
on Preferred Stock (in thousands) $479,532 $240,057 $535,003
Cash Dividends on Common Stock (in thousands) $386,600 $377,800 $325,500
Return on Average Common Equity (percent) 13.06 6.85 16.51
Total Assets (in thousands) $11,130,539 $11,197,494 $10,465,063
Gross Property Additions (in thousands) $929,019 $1,034,059 $1,598,309
- ---------------------------------------------------------------------------------------------------
Capitalization (in thousands):
Common stock equity $3,806,070 $3,538,182 $3,469,201
Preferred stock 657,844 657,844 732,844
Preferred stock subject to mandatory redemption 162,500 166,250 112,500
Preferred securities of subsidiary - - -
Long-term debt 4,861,378 4,825,760 4,464,857
- ---------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) $9,487,792 $9,188,036 $8,779,402
===================================================================================================
Capitalization Ratios (percent):
Common stock equity 40.1 38.5 39.5
Preferred stock 8.6 9.0 9.6
Preferred securities of subsidiary - - -
Long-term debt 51.3 52.5 50.9
- ---------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) 100.0 100.0 100.0
===================================================================================================
First Mortgage Bonds (in thousands):
Issued 150,000 500,000 500,000
Retired 206,677 217,949 377,538
Preferred Stock (in thousands):
Issued - 125,000 100,000
Retired 3,750 150,000 7,500
Preferred Securities of subsidiary (in thousands):
Issued - - -
Retired - - -
- ---------------------------------------------------------------------------------------------------
Security Ratings:
First Mortgage Bonds -
Moody's Baa2 Baa2 Baa1
Standard and Poor's BBB BBB BBB+
Duff & Phelps 9 9 9
Preferred Stock -
Moody's baa2 baa2 baa1
Standard and Poor's BBB- BBB- BBB
Duff & Phelps 10 10 10
- ---------------------------------------------------------------------------------------------------
Customers (year-end):
Residential 1,329,173 1,303,721 1,268,983
Commercial 174,147 169,014 162,258
Industrial 12,353 12,307 12,315
Other 1,993 1,858 1,816
- ---------------------------------------------------------------------------------------------------
Total 1,517,666 1,486,900 1,445,372
===================================================================================================
Employees (year-end) 15,110 14,924 14,773
</TABLE>
<PAGE>
35C
<TABLE>
<CAPTION>
SELECTED FINANCIAL AND OPERATING DATA
Georgia Power Company 1994 Annual Report
======================================================================================
1985 1984
- --------------------------------------------------------------------------------------
<S> <C> <C>
Operating Revenues (in thousands) $3,609,140 $3,319,699
Net Income after Dividends
on Preferred Stock (in thousands) $493,717 $421,719
Cash Dividends on Common Stock (in thousands) $277,500 $225,500
Return on Average Common Equity (percent) 17.95 18.43
Total Assets (in thousands) $9,030,618 $7,880,072
Gross Property Additions (in thousands) $1,384,182 $1,396,846
- --------------------------------------------------------------------------------------
Capitalization (in thousands):
Common stock equity $3,013,707 $2,486,172
Preferred stock 632,844 482,844
Preferred stock subject to mandatory redemption 120,000 127,500
Preferred securities of subsidiary - -
Long-term debt 3,878,066 3,432,606
- --------------------------------------------------------------------------------------
Total (excluding amounts due within one year) $7,644,617 $6,529,122
======================================================================================
Capitalization Ratios (percent):
Common stock equity 39.4 38.1
Preferred stock 9.9 9.3
Preferred securities of subsidiary - -
Long-term debt 50.7 52.6
- --------------------------------------------------------------------------------------
Total (excluding amounts due within one year) 100.0 100.0
======================================================================================
First Mortgage Bonds (in thousands):
Issued - 150,000
Retired 17,738 26,084
Preferred Stock (in thousands):
Issued 150,000 50,000
Retired 3,750
Preferred Securities of subsidiary (in thousands):
Issued - -
Retired - -
- --------------------------------------------------------------------------------------
Security Ratings:
First Mortgage Bonds -
Moody's Baa1 Baa1
Standard and Poor's BBB+ BBB+
Duff & Phelps 9 8
Preferred Stock -
Moody's baa1 baa1
Standard and Poor's BBB BBB
Duff & Phelps 10 9
- --------------------------------------------------------------------------------------
Customers (year-end):
Residential 1,231,140 1,189,670
Commercial 155,399 148,536
Industrial 12,309 12,276
Other 1,789 1,753
- --------------------------------------------------------------------------------------
Total 1,400,637 1,352,235
======================================================================================
Employees (year-end) 14,947 14,562
</TABLE>
<PAGE>
36
<TABLE>
<CAPTION>
SELECTED FINANCIAL AND OPERATING DATA (continued)
Georgia Power Company 1994 Annual Report
===================================================================================================
1994 1993 1992
- ---------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Operating Revenues (in thousands):
Residential $1,180,358 $1,291,035 $1,128,396
Commercial 1,367,315 1,354,130 1,285,681
Industrial 1,100,995 1,113,067 1,083,856
Other 42,983 41,399 39,504
- ---------------------------------------------------------------------------------------------------
Total retail 3,691,651 3,799,631 3,537,437
Sales for resale - non-affiliates 351,591 534,370 640,308
Sales for resale - affiliates 60,899 61,668 67,835
- ---------------------------------------------------------------------------------------------------
Total revenues from sales of electricity 4,104,141 4,395,669 4,245,580
Other revenues 58,262 55,512 51,856
- ---------------------------------------------------------------------------------------------------
Total $4,162,403 $4,451,181 $4,297,436
===================================================================================================
Kilowatt-Hour Sales (in thousands):
Residential 15,680,709 16,649,859 14,939,172
Commercial 18,738,461 18,278,508 17,260,614
Industrial 24,337,632 23,635,363 22,978,312
Other 484,009 460,801 436,144
- ---------------------------------------------------------------------------------------------------
Total retail 59,240,811 59,024,531 55,614,242
Sales for resale - non-affiliates 7,968,475 14,307,030 15,870,222
Sales for resale - affiliates 3,056,050 3,027,733 3,320,060
- ---------------------------------------------------------------------------------------------------
Total 70,265,336 76,359,294 74,804,524
===================================================================================================
Average Revenue Per Kilowatt-Hour (cents):
Residential 7.53 7.75 7.55
Commercial 7.30 7.41 7.45
Industrial 4.52 4.71 4.72
Total retail 6.23 6.44 6.36
Sales for resale 3.74 3.44 3.69
Total sales 5.84 5.76 5.68
Residential Average Annual Kilowatt-Hour Use Per Customer 10,766 11,630 10,603
Residential Average Annual Revenue Per Customer $810.39 $901.79 $800.88
Plant Nameplate Capacity Ratings (year-end) (megawatts) 13,943 13,759 14,076
Maximum Peak-Hour Demand (megawatts) (Note):
Winter 10,509 9,067 8,938
Summer 11,758 12,573 11,448
Annual Load Factor (percent) 63.0 58.5 60.5
Plant Availability (percent):
Fossil-steam 83.1 85.9 86.6
Nuclear 88.4 85.5 87.7
- ---------------------------------------------------------------------------------------------------
Source of Energy Supply (percent):
Coal 61.3 62.1 61.4
Nuclear 18.0 16.2 17.0
Hydro 2.6 2.3 2.5
Oil and gas 0.1 0.2 *
Purchased power -
From non-affiliates 9.7 10.2 12.2
From affiliates 8.3 9.0 6.9
- ---------------------------------------------------------------------------------------------------
Total 100.0 100.0 100.0
===================================================================================================
Total Fuel Economy Data:
BTU per net kilowatt-hour generated 9,915 9,912 9,900
Cost of fuel per million BTU (cents) 145.33 153.62 153.08
Average cost of fuel per net kilowatt-hour generated (cents) 1.44 1.52 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.
</TABLE>
<PAGE>
37A
<TABLE>
<CAPTION>
SELECTED FINANCIAL AND OPERATING DATA (continued)
Georgia Power Company 1994 Annual Report
===================================================================================================
1991 1990 1989
- ---------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Operating Revenues (in thousands):
Residential $1,111,358 $1,109,165 $1,022,781
Commercial 1,243,067 1,218,441 1,143,727
Industrial 1,057,702 1,061,830 1,006,416
Other 37,861 36,773 34,775
- ---------------------------------------------------------------------------------------------------
Total retail 3,449,988 3,426,209 3,207,699
Sales for resale - non-affiliates 736,643 784,086 760,809
Sales for resale - affiliates 65,586 168,251 150,394
- ---------------------------------------------------------------------------------------------------
Total revenues from sales of electricity 4,252,217 4,378,546 4,118,902
Other revenues 49,211 67,263 26,338
- ---------------------------------------------------------------------------------------------------
Total $4,301,428 $4,445,809 $4,145,240
===================================================================================================
Kilowatt-Hour Sales (in thousands):
Residential 14,815,089 14,771,648 14,134,195
Commercial 16,885,833 16,627,128 15,843,181
Industrial 22,298,062 22,126,604 21,801,404
Other 429,016 428,459 414,107
- ---------------------------------------------------------------------------------------------------
Total retail 54,428,000 53,953,839 52,192,887
Sales for resale - non-affiliates 18,719,924 20,158,681 20,479,412
Sales for resale - affiliates 3,885,892 8,272,528 7,489,948
- ---------------------------------------------------------------------------------------------------
Total 77,033,816 82,385,048 80,162,247
===================================================================================================
Average Revenue Per Kilowatt-Hour (cents):
Residential 7.50 7.51 7.24
Commercial 7.36 7.33 7.22
Industrial 4.74 4.80 4.62
Total retail 6.34 6.35 6.15
Sales for resale 3.55 3.35 3.26
Total sales 5.52 5.31 5.14
Residential Average Annual Kilowatt-Hour Use Per Customer 10,675 10,795 10,530
Residential Average Annual Revenue Per Customer $800.78 $810.56 $761.96
Plant Nameplate Capacity Ratings (year-end) (megawatts) 14,076 14,366 14,366
Maximum Peak-Hour Demand (megawatts) (Note):
Winter 10,001 8,977 10,101
Summer 13,090 13,196 12,735
Annual Load Factor (percent) 55.2 55.5 56.3
Plant Availability (percent):
Fossil-steam 93.3 92.5 93.0
Nuclear 81.6 81.3 89.2
- ---------------------------------------------------------------------------------------------------
Source of Energy Supply (percent):
Coal 63.6 65.1 64.0
Nuclear 15.3 13.7 14.1
Hydro 2.3 2.2 2.1
Oil and gas * 0.1 0.1
Purchased power -
From non-affiliates 10.3 11.0 10.2
From affiliates 8.5 7.9 9.5
- ---------------------------------------------------------------------------------------------------
Total 100.0 100.0 100.0
===================================================================================================
Total Fuel Economy Data:
BTU per net kilowatt-hour generated 9,960 9,939 10,020
Cost of fuel per million BTU (cents) 157.97 166.22 164.27
Average cost of fuel per net kilowatt-hour generated (cents) 1.57 1.65 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.
</TABLE>
<PAGE>
37B
<TABLE>
<CAPTION>
SELECTED FINANCIAL AND OPERATING DATA (continued)
Georgia Power Company 1994 Annual Report
===================================================================================================
1988 1987 1986
- ---------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Operating Revenues (in thousands):
Residential $979,047 $904,218 $874,231
Commercial 1,054,995 915,540 854,755
Industrial 983,822 911,933 897,646
Other 31,743 29,350 27,948
- ---------------------------------------------------------------------------------------------------
Total retail 3,049,607 2,761,041 2,654,580
Sales for resale - non-affiliates 707,076 822,696 780,049
Sales for resale - affiliates 86,751 159,998 91,753
- ---------------------------------------------------------------------------------------------------
Total revenues from sales of electricity 3,843,434 3,743,735 3,526,382
Other revenues 54,045 42,750 35,221
- ---------------------------------------------------------------------------------------------------
Total $3,897,479 $3,786,485 $3,561,603
===================================================================================================
Kilowatt-Hour Sales (in thousands):
Residential 13,800,038 13,675,730 13,234,248
Commercial 14,790,561 13,799,379 12,945,926
Industrial 21,412,845 20,884,454 20,339,235
Other 397,669 385,514 381,917
- ---------------------------------------------------------------------------------------------------
Total retail 50,401,113 48,745,077 46,901,326
Sales for resale - non-affiliates 18,544,705 20,910,185 18,198,186
Sales for resale - affiliates 3,327,814 6,032,889 3,160,242
- ---------------------------------------------------------------------------------------------------
Total 72,273,632 75,688,151 68,259,754
===================================================================================================
Average Revenue Per Kilowatt-Hour (cents):
Residential 7.09 6.61 6.61
Commercial 7.13 6.63 6.60
Industrial 4.59 4.37 4.41
Total retail 6.05 5.66 5.66
Sales for resale 3.63 3.65 4.08
Total sales 5.32 4.95 5.17
Residential Average Annual Kilowatt-Hour Use Per Customer 10,484 10,623 10,577
Residential Average Annual Revenue Per Customer $743.82 $702.36 $698.72
Plant Nameplate Capacity Ratings (year-end) (megawatts) 13,018 13,018 11,875
Maximum Peak-Hour Demand (megawatts) (Note):
Winter 9,866 9,446 10,551
Summer 12,295 12,390 11,910
Annual Load Factor (percent) 59.1 56.1 57.5
Plant Availability (percent):
Fossil-steam 94.5 92.7 91.2
Nuclear 69.4 85.4 64.7
- ---------------------------------------------------------------------------------------------------
Source of Energy Supply (percent):
Coal 72.0 70.9 74.6
Nuclear 9.6 9.1 5.0
Hydro 1.2 1.7 1.2
Oil and gas 0.1 0.1 0.6
Purchased power -
From non-affiliates 8.2 8.5 8.9
From affiliates 8.9 9.7 9.7
- ---------------------------------------------------------------------------------------------------
Total 100.0 100.0 100.0
===================================================================================================
Total Fuel Economy Data:
BTU per net kilowatt-hour generated 9,969 9,932 10,016
Cost of fuel per million BTU (cents) 166.28 168.81 175.81
Average cost of fuel per net kilowatt-hour generated (cents) 1.66 1.68 1.76
===================================================================================================
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.
</TABLE>
<PAGE>
37C
<TABLE>
<CAPTION>
SELECTED FINANCIAL AND OPERATING DATA (continued)
Georgia Power Company 1994 Annual Report
======================================================================================
1985 1984
- --------------------------------------------------------------------------------------
<S> <C> <C>
Operating Revenues (in thousands):
Residential $786,500 $754,163
Commercial 797,540 739,035
Industrial 873,554 858,536
Other 26,766 24,388
- --------------------------------------------------------------------------------------
Total retail 2,484,360 2,376,122
Sales for resale - non-affiliates 941,743 779,028
Sales for resale - affiliates 149,463 136,047
- --------------------------------------------------------------------------------------
Total revenues from sales of electricity 3,575,566 3,291,197
Other revenues 33,574 28,502
- --------------------------------------------------------------------------------------
Total $3,609,140 $3,319,699
======================================================================================
Kilowatt-Hour Sales (in thousands):
Residential 12,006,462 11,548,787
Commercial 11,945,938 10,902,163
Industrial 19,517,543 18,862,531
Other 382,238 342,047
- --------------------------------------------------------------------------------------
Total retail 43,852,181 41,655,528
Sales for resale - non-affiliates 21,526,865 19,138,575
Sales for resale - affiliates 5,999,834 4,970,928
- --------------------------------------------------------------------------------------
Total 71,378,880 65,765,031
======================================================================================
Average Revenue Per Kilowatt-Hour (cents):
Residential 6.55 6.53
Commercial 6.68 6.78
Industrial 4.48 4.55
Total retail 5.67 5.70
Sales for resale 3.96 3.80
Total sales 5.01 5.00
Residential Average Annual Kilowatt-Hour Use Per Customer 9,923 9,855
Residential Average Annual Revenue Per Customer $650.01 $643.53
Plant Nameplate Capacity Ratings (year-end) (megawatts) 11,875 11,767
Maximum Peak-Hour Demand (megawatts) (Note):
Winter 10,049 8,462
Summer 11,079 10,443
Annual Load Factor (percent) 56.3 56.9
Plant Availability (percent):
Fossil-steam 91.2 91.0
Nuclear 79.5 47.3
- --------------------------------------------------------------------------------------
Source of Energy Supply (percent):
Coal 72.7 74.4
Nuclear 6.7 4.0
Hydro 1.5 2.7
Oil and gas * *
Purchased power -
From non-affiliates 9.4 9.2
From affiliates 9.7 9.7
- --------------------------------------------------------------------------------------
Total 100.0 100.0
======================================================================================
Total Fuel Economy Data:
BTU per net kilowatt-hour generated 10,089 10,002
Cost of fuel per million BTU (cents) 178.11 184.63
Average cost of fuel per net kilowatt-hour generated (cents) 1.80 1.85
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.
</TABLE>
