Securities registered pursuant to Section 12(b) of the Act:1
Each of the following classes or series of securities registered pursuant to
Section 12(b) of the Act is registered on the New York Stock Exchange.
Indicate by check mark whether the registrants (1) have filed all
reports required to be filed by Section 13 or 15(d) of the Securities Exchange
Act of 1934 during the preceding 12 months (or for such shorter period that the
registrants were required to file such reports), and (2) have been subject to
such filing requirements for the past 90 days. Yes X No___
Indicate by check mark if disclosure of delinquent filers pursuant
to Item 405 of Regulation S-K is not contained herein, and will not be
contained, to the best of registrants' knowledge, in definitive proxy or
information statements incorporated by reference in Part III of this Form 10-K
or any amendment to this Form 10-K. ( )
Aggregate market value of voting stock held by non-affiliates of
The Southern Company at February 28, 1998: $17.1 billion. Each of such other
registrants is a wholly-owned subsidiary of The Southern Company and has no
voting stock other than its common stock. A description of registrants' common
stock follows:
i
CAUTIONARY STATEMENT REGARDING
FORWARD-LOOKING INFORMATION
This Annual Report on Form 10-K includes forward-looking statements in
addition to historical information. The registrants caution that there are
various important factors that could cause actual results to differ materially
from those indicated in the forward-looking statements; accordingly, there can
be no assurance that such indicated results will be realized. These factors
include legislative and regulatory initiatives regarding deregulation and
restructuring of the electric utility industry; the extent and timing of the
entry of additional competition in the markets of SOUTHERN's subsidiaries;
potential business strategies, including acquisitions or dispositions of assets
or internal restructuring, that may be pursued by the registrants; state and
federal rate regulation in the United States; changes in or application of
environmental and other laws and regulations to which SOUTHERN and its
subsidiaries are subject; political, legal and economic conditions and
developments in the United States and in foreign countries in which the
subsidiaries operate; financial market conditions and the results of financing
efforts; changes in commodity prices and interest rates; weather and other
natural phenomena; the performance of projects undertaken by the non-traditional
business and the success of efforts to invest in and develop new opportunities;
and other factors discussed elsewhere herein and in other reports filed from
time to time by the registrants with the SEC.
iii
PART I
Item 1. BUSINESS
SOUTHERN was incorporated under the laws of Delaware on November 9, 1945.
SOUTHERN is domesticated under the laws of Georgia and is qualified to do
business as a foreign corporation under the laws of Alabama. SOUTHERN owns all
the outstanding common stock of ALABAMA, GEORGIA, GULF, MISSISSIPPI and
SAVANNAH, each of which is an operating public utility company. ALABAMA and
GEORGIA each own 50% of the outstanding common stock of SEGCO. The operating
affiliates supply electric service in the states of Alabama, Georgia, Florida,
Mississippi and Georgia, respectively, and SEGCO owns generating units at a
large electric generating station which supplies power to ALABAMA and GEORGIA.
More particular information relating to each of the operating affiliates is as
follows:
ALABAMA is a corporation organized under the laws of the State of Alabama
on November 10, 1927, by the consolidation of a predecessor Alabama Power
Company, Gulf Electric Company and Houston Power Company. The predecessor
Alabama Power Company had had a continuous existence since its
incorporation in 1906.
GEORGIA was incorporated under the laws of the State of Georgia on June
26, 1930, and admitted to do business in Alabama on September 15, 1948.
GULF is a corporation which was organized under the laws of the State of
Maine on November 2, 1925, and admitted to do business in Florida on
January 15, 1926, in Mississippi on October 25, 1976 and in Georgia on
November 20, 1984.
MISSISSIPPI was incorporated under the laws of the State of Mississippi on
July 12, 1972, was admitted to do business in Alabama on November 28,
1972, and effective December 21, 1972, by the merger into it of the
predecessor Mississippi Power Company, succeeded to the business and
properties of the latter company. The predecessor Mississippi Power
Company was incorporated under the laws of the State of Maine on November
24, 1924, and was admitted to do business in Mississippi on December 23,
1924, and in Alabama on December 7, 1962.
SAVANNAH is a corporation existing under the laws of the State of Georgia;
its charter was granted by the Secretary of State on August 5, 1921.
SOUTHERN also owns all the outstanding common stock of Southern Energy,
Southern Communications, Southern Nuclear, SCS (the system service company),
Energy Solutions and other direct and indirect subsidiaries. Southern Energy is
focused on several key international and domestic business lines, including
energy distribution, integrated utilities, stand-alone generation, and other
energy-related products and services. A further description of Southern Energy's
business and organization follows later in this section under "Non-Traditional
Business." Southern Communications provides digital wireless communications
services to SOUTHERN's operating affiliates and also markets these services to
the public within the Southeast. Southern Nuclear provides services to the
Southern electric system's nuclear plants. Energy Solutions develops new
business opportunities related to energy products and services.
SEGCO owns electric generating units with an aggregate capacity of 1,019,680
kilowatts at Plant Gaston on the Coosa River near Wilsonville, Alabama, and
ALABAMA and GEORGIA are each entitled to one-half of SEGCO's capacity and
energy. ALABAMA acts as SEGCO's agent in the operation of SEGCO's units and
furnishes coal to SEGCO as fuel for its units. SEGCO also owns three 230,000
volt transmission lines extending from Plant Gaston to the Georgia state line at
which point connection is made with the GEORGIA transmission line system.
The SOUTHERN System
Traditional Business
The transmission facilities of each of the operating affiliates and SEGCO are
connected to the respective company's own generating plants and other sources of
power and are interconnected with the transmission facilities of the other
operating affiliates and SEGCO by means of heavy-duty high voltage lines. (In
the case of GEORGIA's integrated transmission system, see Item 1 - BUSINESS -
"Territory Served By Operating Affiliates" herein.)
I-1
Operating contracts covering arrangements in effect with principal
neighboring utility systems provide for capacity exchanges, capacity purchases
and sales, transfers of economy energy and other similar transactions.
Additionally, the operating affiliates have entered into voluntary reliability
agreements with the subsidiaries of Entergy Corporation, Florida Electric Power
Coordinating Group and TVA and with Carolina Power & Light Company, Duke Energy
Corporation, South Carolina Electric & Gas Company and Virginia Electric and
Power Company, each of which provides for the establishment and periodic review
of principles and procedures for planning and operation of generation and
transmission facilities, maintenance schedules, load retention programs,
emergency operations, and other matters affecting the reliability of bulk power
supply. The operating affiliates have joined with other utilities in the
Southeast (including those referred to above) to form the SERC to augment
further the reliability and adequacy of bulk power supply. Through the SERC, the
operating affiliates are represented on the National Electric Reliability
Council.
An intra-system interchange agreement provides for coordinating operations
of the power producing facilities of the operating affiliates and SEGCO and the
capacities available to such companies from non-affiliated sources and for the
pooling of surplus energy available for interchange. Coordinated operation of
the entire interconnected system is conducted through a central power supply
coordination office maintained by SCS. The available sources of energy are
allocated to the operating affiliates to provide the most economical sources of
power consistent with good operation. The resulting benefits and savings are
apportioned among the operating affiliates.
SCS has contracted with SOUTHERN, each operating affiliate, Southern Energy,
various of the other subsidiaries, Southern Nuclear and SEGCO to furnish, at
cost and upon request, the following services: general executive and advisory
services, power pool operations, general engineering, design engineering,
purchasing, accounting, finance and treasury, taxes, insurance and pensions,
corporate, rates, budgeting, public relations, employee relations, systems and
procedures and other services with respect to business and operations. Southern
Energy, Energy Solutions and Southern Communications have also secured from the
operating affiliates certain services which are furnished at cost.
Southern Nuclear has contracted with ALABAMA to operate its Farley Nuclear
Plant, as authorized by amendments to the plant operating licenses. Effective
March 22, 1997, Southern Nuclear, pursuant to a contract with GEORGIA, assumed
responsibility for the operation of plants Hatch and Vogtle, as authorized by
amendments to the operating licenses for both plants. See Item 1 BUSINESS -
"Regulation - Atomic Energy Act of 1954" herein.
Non-Traditional Business
SOUTHERN continues to consider new business opportunities, particularly those
which allow use of the expertise and resources developed through its regulated
utility experience. These endeavors began in 1981 and are conducted through
Southern Energy and other subsidiaries. SOUTHERN presently has authorization
from the SEC (the "SEC Order") which in effect will allow it to use the proceeds
from financings for investment in EWGs and FUCOs up to an amount not exceeding
100% of SOUTHERN's consolidated retained earnings. A consumer group that had
sought to intervene in the SEC proceeding has filed an appeal, which remains
pending, with U.S. Court of Appeals for the 11th Circuit seeking judicial review
of the SEC Order. At December 31, 1997, SOUTHERN's consolidated retained
earnings amounted to $3,842 million and its aggregate investment in EWGs and
FUCOs amounted to $2,795 million.
Worldwide, Southern Energy develops and manages electricity and other energy
related projects, including domestic energy trading and marketing.
Reference is made to Note 15 to the financial statements of SOUTHERN in Item
8 herein for additional information regarding SOUTHERN's segment and related
information.
In 1995, SOUTHERN acquired SWEB, one of the United Kingdom's 12 regional
electric distribution companies, for approximately $1.8 billion. In July 1996, a
25 percent interest in SWEB was sold. SWEB is, to some extent, involved in power
generation and certain non-regulated activities which include gas marketing and
telecommunications. In mid-1997, the acquisition of all interest in CEPA was
completed for a total net investment of $2.1 billion. CEPA is engaged in the
business of developing, constructing, owning and operating electric power
I-2
generation facilities. Its current operations include installed operating
capacity of approximately 3,306 megawatts, with projects either completed or
under development in the Philippines, the People's Republic of China, and
Pakistan. In September 1997, Southern Energy acquired a 26% interest in a German
utility for approximately $820 million. For additional information regarding the
acquisitions of SWEB and CEPA, reference is made to Note 14 to SOUTHERN's
financial statements in Item 8 herein.
See Item 2 - PROPERTIES - "Other Electric Generation Facilities" herein for
additional information regarding Southern Energy projects.
As the energy marketplace evolves, Southern Energy is positioning SOUTHERN
to become a major competitor in energy trading and marketing activities. As part
of this strategy, Southern Energy entered into a joint venture with Vastar
Resources effective in January 1998. The two companies combined their energy
trading and marketing operations to form a new full-service energy provider,
Southern Company Energy Marketing. Southern Company Energy Marketing holds a top
10 position in the United States in both natural gas and power marketing.
Southern Energy and Energy Solutions render consulting services and market
SOUTHERN system expertise in the United States and throughout the world. They
contract with other public utilities, commercial concerns and government
agencies for the rendition of services and the licensing of intellectual
property. More specifically, Energy Solutions is focusing on new and existing
programs to enhance customer satisfaction and efficiency and stockholder value,
such as: Good Cents, an energy efficiency program for electric utility
customers; EnerLink, a group of energy management products and services for
large commercial and industrial electricity users; Energy Services, providing
total energy solutions to industrial and commercial customers; other energy
management programs under development; and telecommunications operations related
to energy management programs.
In 1995, Southern Communications began serving SOUTHERN's operating
affiliates and marketing its services to non-affiliates within the Southeast.
The system covers 122,000 square miles and combines the functions of two-way
radio dispatch, cellular phone, short text and numeric messaging and wireless
data transfer.
These continuing efforts to invest in and develop new business opportunities
offer the potential of earning returns which may exceed those of rate-regulated
operations. However, these activities also involve a higher degree of risk.
SOUTHERN expects to make substantial investments over the period 1998-2000 in
these and other new businesses.
Certain Factors Affecting the Industry
Various factors are currently affecting the electric utility industry in
general, including increasing competition and the regulatory changes related
thereto, costs required to comply with environmental regulations, and the
potential for new business opportunities (with their associated risks) outside
of traditional rate-regulated operations. The effects of these and other factors
on the SOUTHERN system are described herein. Particular reference is made to
Item 1 - BUSINESS - "Non-Traditional Business," "Competition" and "Environmental
Regulation."
I-3
Construction Programs
The subsidiary companies of SOUTHERN are engaged in continuous construction
programs to accommodate existing and estimated future loads on their respective
systems. Construction additions or acquisitions of property during 1998 through
2000 by the operating affiliates, SEGCO, SCS, Southern Communications and
Southern Energy are estimated as follows: (in millions)
---------------------------------------------------------
1998 1999 2000
----------------------------
ALABAMA $ 615 $ 723 $ 524
GEORGIA 506 561 549
GULF 68 62 62
MISSISSIPPI 67 92 291
SAVANNAH 22 23 21
SEGCO 3 8 1
SCS 7 15 6
Southern
Communications 67 20 18
Southern Energy* 629 493 78
Other 19 13 18
=========================================================
SOUTHERN system $2,003 $2,010 $1,568
=========================================================
*These construction estimates do not include amounts which may be expended
by Southern Energy on future power production projects or by any subsidiaries
created to effect such future projects. (See Item 1 - BUSINESS -
"Non-Traditional Business" herein.)
I-4
*Southern Communications, SCS and Southern Nuclear plan capital additions to
general plant in 1998 of $67 million, $7 million and $400 thousand,
respectively, while SEGCO plans capital additions of $3 million to generating
facilities. Southern Energy plans capital additions of $555 million to
generating facilities, $73 million to distribution facilities, and $1 million to
general plant. These estimates do not reflect the possibility of Southern
Energy's securing a contract(s) to buy or build additional generating
facilities. Other non-traditional capital additions planned for 1998 are
approximately $19 million. (See Item 1 - BUSINESS - "Non-Traditional Business"
herein.)
The construction programs are subject to periodic review and revision, and
actual construction costs may vary from the above estimates because of numerous
factors. These factors include changes in business conditions; revised load
growth estimates; changes in environmental regulations; changes in existing
nuclear plants to meet new regulatory requirements; increasing costs of labor,
equipment and materials; and cost of capital.
The operating affiliates have approximately 1,600 megawatts of combined
cycle generation scheduled to be placed in service by 2001. In addition,
significant construction will continue related to transmission and distribution
facilities and the upgrading of generating plants . (See Item 2 - PROPERTIES -
"Other Electric Generation Facilities" herein for additional information
relating to facilities under development.)
In 1991, the Georgia legislature passed legislation which requires GEORGIA
and SAVANNAH each to file an Integrated Resource Plan for approval by the
Georgia PSC. Under the plan rules, the Georgia PSC must pre-certify the
construction of new power plants and new purchase power contracts. (See Item 1 -
BUSINESS - "Rate Matters - Integrated Resource Planning" herein.)
See Item 1 - BUSINESS - "Regulation - Environmental Regulation" herein for
information with respect to certain existing and proposed environmental
requirements and Item 2 - PROPERTIES - "Jointly-Owned Facilities" herein for
additional information concerning ALABAMA's and GEORGIA's joint ownership of
certain generating units and related facilities with certain non-affiliated
utilities.
I-5
Financing Programs
In 1997, SOUTHERN raised $360 million from the issuance of new common stock
under SOUTHERN's various stock plans. Also in 1997, SOUTHERN issued a total of
$600 million in trust and capital preferred securities for the direct benefit of
SOUTHERN. SOUTHERN plans to issue additional equity capital in 1998. The amount
and timing of additional equity capital to be raised in 1998, as well as
subsequent years, will be contingent on SOUTHERN's investment opportunities.
Equity capital can be provided from any combination of public offerings, private
placements, or SOUTHERN's stock plans. Any portion of the common stock required
during 1998 for SOUTHERN's stock plans that is not provided from the issuance of
new stock will be acquired on the open market in accordance with the terms of
such plans.
The operating affiliates plan to obtain the funds required for construction
and other purposes from sources similar to those used in the past, which was
primarily from internal sources. However, the type and timing of any financings
-- if needed -- will depend on market conditions and regulatory approval.
Historically the operating affiliates have relied on issuances of first mortgage
bonds and preferred stock, in addition to pollution control revenue bonds issued
for their benefit by public authorities, to meet their long-term external
financing requirements. Recently, financings have consisted of unsecured debt
and trust preferred securities. In this regard, the operating affiliates --
except SAVANNAH -- sought and obtained stockholder approval in 1997 to amend
their respective corporate charters eliminating restrictions on the amount of
unsecured indebtedness they may incur.
Short-term debt is often utilized as appropriate at SOUTHERN and the
operating affiliates. The amount of securities representing short-term unsecured
indebtedness allowable under SAVANNAH's charter at December 31, 1997 was $71
million (20% of secured indebtedness and other capital). Under the provisions of
SAVANNAH's charter, this percentage will be reduced to 10% on July 1, 1999. In
the case of ALABAMA, GEORGIA, GULF and MISSISSIPPI, preferred shareholders
approved the removal of restrictions on unsecured indebtedness under the
respective charters. SOUTHERN does not have a charter limitation on short-term
unsecured indebtedness.
The maximum amounts of short-term or term-loan indebtedness authorized by
the appropriate regulatory authorities are shown on the following table:
Outstanding at
Amount December 31, 1997
------------ ---------------------
(in millions)
ALABAMA $ 750 (1) $306.9
GEORGIA 1,700 (2) 366.2
GULF 300(1) 82.3
MISSISSIPPI 350(1) 80.0
SAVANNAH 90(2) 30.0
SOUTHERN 2,000(1) 768.7
------------------------------------------------------
Notes:
(1) ALABAMA's authority is based on authorization received from the Alabama
PSC, which expires December 31, 1998. No SEC authorization is required for
ALABAMA. GULF, MISSISSIPPI and SOUTHERN have received SEC authorization to issue
from time to time short-term and/or term-loan notes to banks and commercial
paper to dealers in the amounts shown through December 31, 2003, December 31,
2002 and March 31, 2001, respectively.
(2) GEORGIA and SAVANNAH have received SEC authorization to issue from time
to time short-term and term-loan notes to banks and commercial paper to dealers
in the amounts shown through December 31, 2002. Authorization for term-loan
indebtedness is also required by and has been received from the Georgia PSC.
Currently, GEORGIA and SAVANNAH have remaining authority from the Georgia PSC of
$1.4 billion and $96.1 million, respectively, expiring December 31, 1998.
Reference is made to Note 5 to the financial statements for SOUTHERN,
ALABAMA, GULF, MISSISSIPPI and SAVANNAH and Note 9 to the financial statements
for GEORGIA in Item 8 herein for information regarding the registrants' credit
arrangements.
New projects undertaken by subsidiaries of Southern Energy are generally
financed through a combination of equity funds
provided by SOUTHERN and non-recourse debt incurred on a project-specific basis.
I-6
Fuel Supply
The operating affiliates' and SEGCO's supply of electricity is derived
predominantly from coal. The sources of generation for the years 1995 through
1997 and the estimates for 1998 are shown below:
Oil and
ALABAMA Coal Nuclear Hydro Gas
--------- ---------- --------- ---------
1995 73% 19% 8% *
1996 72 20 8 *
1997 72 19 8 1
1998 74 18 7 1
GEORGIA
1995 74 22 3 1
1996 74 22 3 1
1997 75 22 2 1
1998 75 21 3 1
GULF
1995 99 ** ** 1
1996 99 ** ** 1
1997 100 ** ** *
1998 99 ** ** 1
MISSISSIPPI
1995 79 ** ** 21
1996 85 ** ** 15
1997 85 ** ** 15
1998 85 ** ** 15
SAVANNAH
1995 80 ** ** 20
1996 90 ** ** 10
1997 87 ** ** 13
1998 88 ** ** 12
SEGCO
1995 100 ** ** *
1996 100 ** ** *
1997 100 ** ** *
1998 100 ** ** *
SOUTHERN system***
1995 77 17 4 2
1996 77 17 4 2
1997 77 17 4 2
1998 79 16 4 1
---------------------------------------------------------
*Less than 0.5%.
**Not applicable.
***Amounts shown for the SOUTHERN system are weighted
averages of the operating affiliates and SEGCO.
The average costs of fuel in cents per net kilowatt-hour generated for 1995
through 1997 are shown below:
Oil and Weighted
ALABAMA Coal Nuclear Gas Average
--------- ---------- ----------- -----------
1995 1.71 0.50 * 1.48
1996 1.71 0.50 * 1.46
1997 1.73 0.54 * 1.49
GEORGIA
1995 1.67 0.60 4.68 1.44
1996 1.55 0.55 5.50 1.35
1997 1.53 0.52 5.19 1.32
GULF
1995 2.08 ** 3.56 2.09
1996 1.99 ** 6.41 2.02
1997 1.97 ** 5.59 1.99
MISSISSIPPI
1995 1.58 ** 2.33 1.64
1996 1.43 ** 4.32 1.57
1997 1.44 ** 3.54 1.57
SAVANNAH
1995 1.77 ** 3.80 2.18
1996 1.76 ** 8.41 2.42
1997 1.91 ** 4.63 2.27
SEGCO
1995 1.87 ** * 1.87
1996 1.72 ** * 1.72
1997 1.51 ** * 1.51
SOUTHERN system***
1995 1.73 0.56 3.37 1.53
1996 1.65 0.52 5.20 1.48
1997 1.63 0.53 4.38 1.46
----------------------------------------------------------------
* Not meaningful because of minimal generation from fuel source.
** Not applicable.
*** Amounts shown for the SOUTHERN system are weighted averages of the
operating affiliates and SEGCO. See SELECTED FINANCIAL DATA in Item 6
herein for each registrant's source of energy supply.
I-7
As of February 13, 1998, the operating affiliates and SEGCO had stockpiles
of coal on hand at their respective coal-fired plants which represented an
estimated 23 days of recoverable supply for bituminous coal and 27 days for
sub-bituminous coal. It is estimated that approximately 66.6 million tons of
coal will be consumed in 1998 by the operating affiliates and SEGCO (including
those units GEORGIA owns jointly with OPC, MEAG and Dalton and operates for FP&L
and JEA and the units ALABAMA owns jointly with AEC). The operating affiliates
and SEGCO currently have 31 coal contracts. These contracts cover remaining
terms of up to 14 years. Approximately 16% of 1998 estimated coal requirements
will be purchased in the spot market. Management has set a goal whereby the spot
market should be utilized, absent the transition from coal contract expirations,
for 20 to 30% of the SOUTHERN system's coal supply. Additionally, it has been
determined that approximately 30 days of recoverable supply is the appropriate
level for coal stockpiles. During 1997, the operating affiliates' and SEGCO's
average price of coal delivered was approximately $36.8 per ton.
The typical sulfur content of coal purchased under contracts ranges from
approximately 0.49% to 2.76% sulfur by weight. Fuel sulfur restrictions and
other environmental limitations have increased significantly and may increase
further the difficulty and cost of obtaining an adequate coal supply. See Item 1
- BUSINESS - "Regulation - Environmental Regulation" herein.
Changes in fuel prices are generally reflected in fuel adjustment clauses
contained in rate schedules. See Item 1 - BUSINESS -"Rate Matters - Rate
Structure" herein.
ALABAMA owns coal lands and mineral rights in the Warrior Coal Field,
located northwest of Birmingham in the vicinity of its Gorgas Steam Plant. SEGCO
also owns coal reserves in the Warrior Coal Field and in the Cahaba Coal Field,
which is located southwest of Birmingham. ALABAMA has agreements with
non-affiliated industrial and mining firms to mine coal from ALABAMA's reserves,
as well as their own reserves, for supply to ALABAMA's generating units.
The operating affiliates have renegotiated, bought out or otherwise
terminated various coal supply contracts. For more information on certain of
these transactions, see Note 5 to the financial statements of GULF in Item 8
herein.
ALABAMA and GEORGIA have numerous contracts covering a portion of their
nuclear fuel needs for uranium, conversion services, enrichment services and
fuel fabrication. These contracts have varying expiration dates and most are
short to medium term (less than 10 years). Management believes that sufficient
capacity for nuclear fuel supplies and processing exists to preclude the
impairment of normal operations of the SOUTHERN system's nuclear generating
units.
ALABAMA and GEORGIA have contracts with the DOE that provide for the
permanent disposal of spent nuclear fuel. Although disposal was scheduled to
begin in 1998, the actual year this service will begin is uncertain. Sufficient
storage capacity currently is available to permit operation into 2003 at Plant
Hatch, into 2008 at Plant Vogtle, and into 2010 and 2013 at Plant Farley units 1
and 2, respectively. Activities for adding dry cask storage capacity at Plant
Hatch by as early as 1999 are in progress.
The Energy Act imposed upon utilities with nuclear plants, including ALABAMA
and GEORGIA, obligations for the decontamination and decommissioning of federal
nuclear fuel enrichment facilities. See Note 1 to SOUTHERN's, ALABAMA's and
GEORGIA's financial statements in Item 8 herein.
Territory Served By Operating Affiliates
The territory in which the operating affiliates provide electric service
comprises most of the states of Alabama and Georgia together with the
northwestern portion of Florida and southeastern Mississippi. In this territory
there are non-affiliated electric distribution systems which obtain some or all
of their power requirements either directly or indirectly from the operating
affiliates. The territory has an area of approximately 120,000 square miles and
an estimated population of approximately 11 million.
ALABAMA is engaged, within the State of Alabama, in the generation and
purchase of electricity and the distribution and sale of such electricity at
retail in over 1,000 communities (including Anniston, Birmingham, Gadsden,
I-8
Mobile, Montgomery and Tuscaloosa) and at wholesale to 15 municipally-owned
electric distribution systems, 11 of which are served indirectly through sales
to AMEA, and two rural distributing cooperative associations. ALABAMA also
supplies steam service in downtown Birmingham. ALABAMA owns coal reserves near
its steam-electric generating plant at Gorgas and uses the output of coal from
these reserves in some of its generating plants. ALABAMA also sells, and
cooperates with dealers in promoting the sale of, electric appliances.
GEORGIA is engaged in the generation and purchase of electricity and the
distribution and sale of such electricity within the State of Georgia at retail
in over 600 communities (including Athens, Atlanta, Augusta, Columbus, Macon,
Rome and Valdosta), as well as in rural areas, and at wholesale currently to 39
electric cooperative associations through a power supply arrangement with OPC, a
corporate cooperative of electric membership cooperatives in Georgia, and to 50
municipalities, 48 of which are served through a power supply arrangement with
MEAG, a public corporation and an instrumentality of the State of Georgia.
GULF is engaged, within the northwestern portion of Florida, in the
generation and purchase of electricity and the distribution and sale of such
electricity at retail in 71 communities (including Pensacola, Panama City and
Fort Walton Beach), as well as in rural areas, and at wholesale to a
non-affiliated utility and a municipality. GULF also sells electric appliances.
MISSISSIPPI is engaged in the generation and purchase of electricity and the
distribution and sale of such energy within the 23 counties of southeastern
Mississippi, at retail in 123 communities (including Biloxi, Gulfport,
Hattiesburg, Laurel, Meridian and Pascagoula), as well as in rural areas, and at
wholesale to one municipality, six rural electric distribution cooperative
associations and one generating and transmitting cooperative.
SAVANNAH is engaged, within a five-county area in eastern Georgia, in the
generation and purchase of electricity and the distribution and sale of such
electricity at retail and, as a member of the SOUTHERN system power pool, the
transmission and sale of wholesale energy.
For information relating to kilowatt-hour sales by classification for each
registrant, reference is made to "Management's Discussion and Analysis-Revenues"
in Item 7 herein. Also, for information relating to the sources of revenues for
the Southern system and each of the operating affiliates, reference is made to
Item 6 herein.
A portion of the area served by SOUTHERN's operating affiliates adjoins the
area served by TVA and its municipal and cooperative distributors. An Act of
Congress limits the distribution of TVA power, unless otherwise authorized by
Congress, to specified areas or customers which generally were those served on
July 1, 1957.
The RUS has authority to make loans to cooperative associations or
corporations to enable them to provide electric service to customers in rural
sections of the country. There are 71 electric cooperative organizations
operating in the territory in which the operating affiliates provide electric
service at retail or wholesale.
One of these, AEC, is a generating and transmitting cooperative selling
power to several distributing cooperatives, municipal systems and other
customers in south Alabama and northwest Florida. AEC owns generating units with
approximately 840 megawatts of nameplate capacity, including an undivided
ownership interest in ALABAMA's Plant Miller Units 1 and 2. AEC's facilities
were financed with RUS loans secured by long-term contracts requiring
distributing cooperatives to take their requirements from AEC to the extent such
energy is available. Two of the 14 distributing cooperatives operating in
ALABAMA's service territory obtain a portion of their power requirements
directly from ALABAMA.
Four electric cooperative associations, financed by the RUS, operate within
GULF's service area. These cooperatives purchase their full requirements from
AEC and SEPA. A non-affiliated utility also operates within GULF's service area
and purchases a portion of its requirements from GULF.
ALABAMA and GULF have entered into separate agreements with AEC involving
interconnection between the respective systems and, in the case of ALABAMA, the
delivery of capacity and energy from AEC to certain distributing cooperatives.
I-9
The rates for the various services provided by ALABAMA and GULF to AEC are based
on formulary approaches which result in the charges by each company being
updated annually, subject to FERC approval. See Item 2 - PROPERTIES -
"Jointly-Owned Facilities" herein for details of ALABAMA's joint-ownership with
AEC of a portion of Plant Miller.
Another of the 71 electric cooperatives is SMEPA, also a generating and
transmitting cooperative. SMEPA has a generating capacity of 739,000 kilowatts
and a transmission system estimated to be 1,357 miles in length. MISSISSIPPI has
an interchange agreement with SMEPA pursuant to which various services are
provided, including the furnishing of protective capacity by MISSISSIPPI to
SMEPA.
There are 43 electric cooperative organizations operating in, or in areas
adjoining, territory in the State of Georgia in which GEORGIA provides electric
service at retail or wholesale. Three of these organizations obtain their power
from TVA and one from other sources. Since July 1, 1975, OPC has supplied the
requirements of the remaining 39 of these cooperative organizations from
self-owned generation acquired from GEORGIA and, until September 1991, through
partial requirements purchases from GEORGIA. GEORGIA entered into an agreement
with OPC pursuant to which, effective in September 1991, OPC ceased to be a
partial requirements wholesale customer of GEORGIA. Instead, OPC began the
purchase of 1,250 megawatts of capacity from GEORGIA through 1999, subject to
reduction or extension by OPC, and may satisfy the balance of its needs through
purchases from others. OPC decreased its purchases of capacity by 250 megawatts
each in September 1996 and 1997 and has notified GEORGIA of its intent to
decrease purchases of capacity by an additional 250 megawatts in September 1998
and 1999. Under the amended 1995 Integrated Resource Plan approved by the
Georgia PSC in March 1997, the resources associated with the decreased purchases
in 1996, 1997 and 1998 will be used to meet the needs of GEORGIA's retail
customers through 2004.
There are 65 municipally-owned electric distribution systems operating in
the territory in which SOUTHERN's operating affiliates provide electric service
at retail or wholesale.
AMEA was organized under an act of the Alabama legislature and is comprised
of 11 municipalities. In 1986, ALABAMA entered into a firm power purchase
contract with AMEA entitling AMEA to scheduled amounts of capacity (to a maximum
of 100 megawatts) for a period of 15 years commencing September 1, 1986. In
October 1991, ALABAMA entered into a second firm power purchase contract with
AMEA entitling AMEA to scheduled amounts of additional capacity (to a maximum 80
megawatts) for a period of 15 years commencing October 1, 1991. In both
contracts the power will be sold to AMEA for its member municipalities that
previously were served directly by ALABAMA as wholesale customers. Under the
terms of the contracts, ALABAMA received payments from AMEA representing the net
present value of the revenues associated with the respective capacity
entitlements. See Note 7 to ALABAMA's financial statements in Item 8 herein for
further information on these contracts.
Forty-seven municipally-owned electric distribution systems and one
county-owned system receive their requirements through MEAG, which was
established by a state statute in 1975. MEAG serves these requirements from
self-owned generation facilities acquired from GEORGIA and purchases from
others. In August 1997, a new power supply contract was implemented between
GEORGIA and MEAG that replaced the partial requirements tariff pursuant to which
GEORGIA previously sold wholesale energy to MEAG. Since 1977 Dalton has filled
its requirements from generation facilities acquired from GEORGIA and through
partial requirements purchases. One municipally-owned electric distribution
system's full requirements are served under a market-based contract by GEORGIA.
(See Item 2 - PROPERTIES - "Jointly-Owned Facilities" herein.)
GULF and MISSISSIPPI provide wholesale requirements for one municipal system
each.
GEORGIA has entered into substantially similar agreements with Georgia
Transmission Corporation (formerly OPC's transmission division), MEAG and Dalton
providing for the establishment of an integrated transmission system to carry
the power and energy of each. The agreements require an investment by each party
in the integrated transmission system in proportion to its respective share of
the aggregate system load. (See Item 2 - PROPERTIES - "Jointly-Owned Facilities"
herein.)
I-10
SCS, acting on behalf of ALABAMA, GEORGIA, GULF, MISSISSIPPI and SAVANNAH,
also has a contract with SEPA (a federal power marketing agency) providing for
the use of those companies' facilities at government expense to deliver to
certain cooperatives and municipalities, entitled by federal statute to
preference in the purchase of power from SEPA, quantities of power equivalent to
the amounts of power allocated to them by SEPA from certain United States
Government hydroelectric projects.
The retail service rights of all electric suppliers in the State of Georgia
are regulated by the 1973 State Territorial Electric Service Act. Pursuant to
the provisions of this Act, all areas within existing municipal limits were
assigned to the primary electric supplier therein on March 29, 1973 (451
municipalities, including Atlanta, Columbus, Macon, Augusta, Athens, Rome and
Valdosta, to GEORGIA; 115 to electric cooperatives; and 50 to publicly-owned
systems). Areas outside of such municipal limits were either to be assigned or
to be declared open for customer choice of supplier by action of the Georgia PSC
pursuant to standards set forth in the Act. Consistent with such standards, the
Georgia PSC has assigned substantially all of the land area in the state to a
supplier. Notwithstanding such assignments, the Act provides that any new
customer locating outside of 1973 municipal limits and having a connected load
of at least 900 kilowatts may receive electric service from the supplier of its
choice. (See also Item 1 - BUSINESS - "Competition" herein.)
Under and subject to the provisions of its franchises and concessions and
the 1973 State Territorial Electric Service Act, SAVANNAH has the full but
nonexclusive right to serve the City of Savannah, the Towns of Bloomingdale,
Pooler, Garden City, Guyton, Newington, Oliver, Port Wentworth, Rincon, Tybee
Island, Springfield, Thunderbolt, Vernonburg, and in conjunction with a
secondary supplier, the Town of Richmond Hill. In addition, SAVANNAH has been
assigned certain unincorporated areas in Chatham, Effingham, Bryan, Bulloch and
Screven Counties by the Georgia PSC. (See also Item 1 - BUSINESS - "Competition"
herein.)
Pursuant to the 1956 Utility Act, the Mississippi PSC issued "Grandfather
Certificates" of public convenience and necessity to MISSISSIPPI and to six
distribution rural cooperatives operating in southeastern Mississippi, then
served in whole or in part by MISSISSIPPI, authorizing them to distribute
electricity in certain specified geographically described areas of the state.
The six cooperatives serve approximately 300,000 retail customers in a
certificated area of approximately 10,300 square miles. In areas included in a
"Grandfather Certificate," the utility holding such certificate may, without
further certification, extend its lines up to five miles; other extensions
within that area by such utility, or by other utilities, may not be made except
upon a showing of, and a grant of a certificate of, public convenience and
necessity. Areas included in such a certificate which are subsequently annexed
to municipalities may continue to be served by the holder of the certificate,
irrespective of whether it has a franchise in the annexing municipality. On the
other hand, the holder of the municipal franchise may not extend service into
such newly annexed area without authorization by the Mississippi PSC.
Long-Term Power Sales Agreements
Reference is made to Note 7 to the financial statements for SOUTHERN, ALABAMA,
GEORGIA, GULF and MISSISSIPPI in Item 8 herein for information regarding
contracts for the sales of capacity and energy to non-territorial customers.
Competition
The electric utility industry in the United States is currently undergoing a
period of dramatic change as a result of regulatory and competitive factors.
Among the primary agents of change has been the Energy Policy Act of 1992
(Energy Act). The Energy Act allows independent power producers (IPPs) to access
a utility's transmission network in order to sell electricity to other
utilities. This enhances the incentive for IPPs to build cogeneration plants for
a utility's large industrial and commercial customers, and sell energy
generation to other utilities. Also, electricity sales for resale rates are
being driven down by wholesale transmission access and numerous potential new
energy suppliers, including power marketers and brokers. SOUTHERN is
I-11
aggressively working to maintain and expand its share of wholesale sales in the
Southeastern power markets.
Although the Energy Act does not permit retail customer access, it was a
major catalyst for the current restructuring and consolidation taking place
within the utility industry. Numerous federal and state initiatives are in
varying stages to promote wholesale and retail competition. Among other things,
these initiatives allow customers to choose their electricity provider. As these
initiatives materialize, the structure of the utility industry could radically
change. Some states have approved initiatives that result in a separation of the
ownership and/or operation of generating facilities from the ownership and/or
operation of transmission and distribution facilities. While various
restructuring and competition initiatives have been or are being discussed in
Alabama, Florida, Georgia, and Mississippi, none have been enacted to date.
Enactment would require numerous issues to be resolved, including significant
ones relating to transmission pricing and recovery of any stranded investments.
The inability of an operating company to recover its investments, including the
regulatory assets described in Note 1 to each registrant's respective financial
statements, could have a material adverse effect on the financial condition of
that operating company. The operating companies are attempting to minimize or
reduce their cost exposure. Reference is made to Note 3 to the financial
statements for SOUTHERN for information regarding these efforts.
Continuing to be a low-cost producer could provide opportunities to
increase market share and profitability in markets that evolve with changing
regulation. Conversely, unless SOUTHERN 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. Reference is made to each registrant's
"Management's Discussion and Analysis - Future Earnings Potential" in Item 7
herein for further discussion of competition.
In order to adapt to a less regulated, more competitive environment,
SOUTHERN continues to evaluate and consider a wide array of potential business
strategies. These strategies may include business combinations, acquisitions
involving other utility or non-utility businesses or properties, internal
restructuring, disposition of certain assets, or some combination thereof.
Furthermore, SOUTHERN may engage in other new business ventures that arise from
competitive and regulatory changes in the utility industry. Pursuit of any of
the above strategies, or any combination thereof, may significantly affect the
business operations and financial condition of SOUTHERN. (See Item 1 - BUSINESS
- "Non-Traditional Business" herein.)
As a result of the foregoing factors, SOUTHERN has experienced increasing
competition for available off-system sales of capacity and energy from
neighboring utilities and alternative sources of energy. Additionally, the
future effect of cogeneration and small-power production facilities on the
SOUTHERN system cannot currently be determined but may be adverse.
ALABAMA currently has cogeneration contracts in effect with nine industrial
customers. Under the terms of these contracts, ALABAMA purchases excess
generation of such companies. During 1997, ALABAMA purchased approximately 57
million kilowatt-hours from such companies at a cost of $1.0 million.
GEORGIA currently has cogeneration contracts in effect with six industrial
customers. Under the terms of these contracts, GEORGIA purchases excess
generation of such companies. During 1997, GEORGIA purchased 5.3 million
kilowatt-hours from such companies at a cost of $117,304. GEORGIA has entered
into a 30-year purchase power agreement, scheduled to begin in June 1998, for
electricity from a 300-megawatt cogeneration facility. Payments are subject to
reductions for failure to meet minimum capacity output. Reference is made to
Note 4 to the financial statements for GEORGIA in Item 8 herein for information
regarding purchase power commitments.
GULF currently has cogeneration agreements for "as available" energy in
effect with two industrial customers. During 1997, GULF purchased 98 million
kilowatt-hours from such companies for $2 million.
MISSISSIPPI entered into agreements to purchase options for summer peaking
power for the years 1997 through 2000. Also, the Company has purchased options
from power marketers. Reference is made to Note 5 to the financial statements
for MISSISSIPPI in Item 8 herein for information regarding fuel and purchased
power commitments.
I-12
SAVANNAH currently has cogeneration contracts in effect with five industrial
customers. Under the terms of these contracts, SAVANNAH purchases excess
generation of such companies. During 1997, SAVANNAH purchased 1 million
kilowatt-hours from such companies at a cost of $19,000.
The competition for retail energy sales among competing suppliers of energy
is influenced by various factors, including price, availability, technological
advancements and reliability. These factors are, in turn, affected by, among
other influences, regulatory, political and environmental considerations,
taxation and supply.
The operating affiliates have experienced, and expect to continue to
experience, competition in their respective retail service territories in
varying degrees as the result of self-generation (as described above) and fuel
switching by customers and other factors. (See also Item 1 - BUSINESS -
"Territory Served By Operating Affiliates" herein for information concerning
suppliers of electricity operating within or near the areas served at retail by
the operating affiliates.)
Regulation
State Commissions
The operating affiliates and SEGCO are subject to the jurisdiction of their
respective state regulatory commissions, which have broad powers of supervision
and regulation over public utilities operating in the respective states,
including their rates, service regulations, sales of securities (except for the
Mississippi PSC) and, in the cases of the Georgia PSC and Mississippi PSC, in
part, retail service territories. (See Item 1 - BUSINESS - "Rate Matters" and
"Territory Served By Operating Affiliates" herein.)
Holding Company Act
SOUTHERN is registered as a holding company under the Holding Company Act, and
it and its subsidiary companies are subject to the regulatory provisions of said
Act, including provisions relating to the issuance of securities, sales and
acquisitions of securities and utility assets, services performed by SCS and
Southern Nuclear, and the activities of certain of SOUTHERN's special purpose
subsidiaries.
While various proposals have been introduced in Congress regarding the
Holding Company Act, the prospects for legislative reform or repeal are
uncertain at this time.
Federal Power Act
The Federal Power Act subjects the operating affiliates and SEGCO to regulation
by the FERC as companies engaged in the transmission or sale at wholesale of
electric energy in interstate commerce, including regulation of accounting
policies and practices.
Reference is made to Note 3 to each registrant's financial statements
(except SAVANNAH) in Item 8 herein for further information regarding FERC
reviews of equity returns.
ALABAMA and GEORGIA are also subject to the provisions of the Federal Power
Act or the earlier Federal Water Power Act applicable to licensees with respect
to their hydroelectric developments. Among the hydroelectric projects subject to
licensing by the FERC are 14 existing ALABAMA generating stations having an
aggregate installed capacity of 1,582,725 kilowatts and 18 existing GEORGIA
generating stations having an aggregate installed capacity of 1,074,696
kilowatts.
GEORGIA filed, in September, 1996, with the FERC, a notice of its intent to
seek a new license for the Flint River Project. GEORGIA must file a new license
by September 1999.
GEORGIA and OPC also have a license, expiring in 2027, for the Rocky
Mountain Plant, a pure pumped storage facility of 847,800 kilowatt capacity
which began commercial operation in 1995. (See Item 2 - PROPERTIES -
"Jointly-Owned Facilities" herein and Note 3 to SOUTHERN's and GEORGIA's
financial statements in Item 8 herein for additional information.)
Licenses for all projects, excluding those discussed above, expire in the
period 2007-2023 in the case of ALABAMA's projects and in the period 2005-2036
in the case of GEORGIA's projects.
I-13
Upon or after the expiration of each license, the United States Government,
by act of Congress, may take over the project, or the FERC may relicense the
project either to the original licensee or to a new licensee. In the event of
takeover or relicensing to another, the original licensee is to be compensated
in accordance with the provisions of the Federal Power Act, such compensation to
reflect the net investment of the licensee in the project, not in excess of the
fair value of the property taken, plus reasonable damages to other property of
the licensee resulting from the severance therefrom of the property taken.
Atomic Energy Act of 1954
ALABAMA, GEORGIA and Southern Nuclear are subject to the provisions of the
Atomic Energy Act of 1954, as amended, which vests jurisdiction in the NRC over
the construction and operation of nuclear reactors, particularly with regard to
certain public health and safety and antitrust matters. The National
Environmental Policy Act has been construed to expand the jurisdiction of the
NRC to consider the environmental impact of a facility licensed under the Atomic
Energy Act of 1954, as amended.
Reference is made to Notes 1 and 13 to SOUTHERN's, Notes 1 and 12 to
ALABAMA's and Notes 1 and 5 to GEORGIA's financial statements in Item 8 herein
for information on nuclear decommissioning costs and nuclear insurance.
Additionally, Note 3 to GEORGIA's financial statements contains information
regarding nuclear performance standards imposed by the Georgia PSC that may
impact retail rates.
Environmental Regulation
The operating affiliates and SEGCO are subject to federal, state and local
environmental requirements which, among other things, control emissions of
particulates, sulfur dioxide and nitrogen oxides into the air; the use,
transportation, storage and disposal of hazardous and toxic waste; and
discharges of pollutants, including thermal discharges, into waters of the
United States. The operating affiliates and SEGCO expect to comply with such
requirements, which generally are becoming increasingly stringent, through
technical improvements, the use of appropriate combinations of low-sulfur fuel
and chemicals, addition of environmental control facilities, changes in control
techniques and reduction of the operating levels of generating facilities.
Failure to comply with such requirements could result in the complete shutdown
of individual facilities not in compliance as well as the imposition of civil
and criminal penalties.
Reference is made to each registrant's "Management's Discussion and
Analysis" in Item 7 herein for a discussion of the Clean Air Act and other
environmental legislation and proceedings.
Possible adverse health effects of EMFs from various
sources, including transmission and distribution lines, have been the subject of
a number of studies and increasing public discussion. The scientific research
currently is inconclusive as to whether EMFs may cause adverse health effects.
However, there is the possibility of passage of legislation and promulgation of
rulemaking that would require measures to mitigate EMFs, with resulting
increases in capital and operating costs. In addition, the potential exists for
public liability with respect to lawsuits brought by plaintiffs alleging damages
caused by EMFs.
The operating affiliates' and SEGCO's estimated capital expenditures for
environmental quality control facilities for the years 1998, 1999 and 2000 are
as follows: (in millions)
---------------- -- ------------ ------------ -----------
1998 1999 2000
------------ ------------ -----------
ALABAMA $18.3 $63.8 $19.6
GEORGIA 13.0 14.0 1.0
GULF 9.3 1.9 0.1
MISSISSIPPI 15.0 6.0 -
SAVANNAH - - -
SEGCO 0.7 7.6 0.5
------------ ------------ -----------
SOUTHERN
system $56.3 $93.3 $21.2
================ == ============ ============ ===========
*The foregoing estimates are included in the current construction programs.
(See Item 1 - BUSINESS - "Construction Programs" herein.)
Additionally, each operating affiliate and SEGCO have incurred costs for
environmental remediation of various sites. Reference is made to each
registrant's "Management's Discussion and Analysis" in Item 7 herein for
information regarding the registrants' environmental remediation efforts. Also,
see Note 3 to SOUTHERN's and GEORGIA's financial statements in Item 8 herein for
I-14
information regarding the identification of sites that may require environmental
remediation by GEORGIA and Note 3 to MISSISSIPPI's financial statements in Item
8 herein for information regarding a site that may require environmental
remediation by MISSISSIPPI.
The operating affiliates and SEGCO are unable to predict at this time what
additional steps they may be required to take as a result of the implementation
of existing or future quality control requirements for air, water and hazardous
or toxic materials, but such steps could adversely affect system operations and
result in substantial additional costs.
The outcome of the matters mentioned above under "Regulation" cannot now be
determined, except that these developments may result in delays in obtaining
appropriate licenses for generating facilities, increased construction and
operating costs, or reduced generation, the nature and extent of which, while
not determinable at this time, could be substantial.
Rate Matters
Rate Structure
The rates and service regulations of the operating affiliates are uniform for
each class of service throughout their respective service areas. Rates for
residential electric service are generally of the block type based upon
kilowatt-hours used and include minimum charges.
Residential and other rates contain separate customer charges. Rates for
commercial service are presently of the block type and, for large customers, the
billing demand is generally used to determine capacity and minimum bill charges.
These large customers' rates are generally based upon usage by the customer
including those with special features to encourage off-peak usage. Additionally,
the operating affiliates are allowed by their respective PSCs to negotiate the
terms and compensation of service to large customers. Such terms and
compensation of service, however, are subject to final PSC approval. ALABAMA and
GEORGIA are allowed by state law to recover fuel and net purchased energy costs
through fuel cost recovery provisions which are adjusted to reflect increases or
decreases in such costs. GULF and SAVANNAH recover from retail customers fuel
and net purchased power costs through provisions which are adjusted to reflect
increases or decreases in such costs. GULF's recovery of fuel costs is based
upon a projection for six-months - any over/under recovery during such period is
reflected in a subsequent six-month period with interest. GULF's recovery of
purchased power capacity costs is based upon an annual projection - any
over/under recovery during such period is reflected in a subsequent annual
period with interest. With respect to MISSISSIPPI's retail rates, fuel and
purchased power costs above base levels included in the various rate schedules
are billed to such customers under the fuel and energy adjustment clause. The
adjustment factors for MISSISSIPPI's retail and wholesale rates are generally
levelized based on the estimated energy cost for the year, adjusted for any
actual over/under collection from the previous year. However, in January 1998,
MISSISSIPPI received approval from the MPSC to change its Fuel Adjustment Clause
and to levelize and fix its Fuel Adjustment Factors for January 1998 through
December 2000. Revenues are adjusted for differences between recoverable fuel
costs and amounts actually recovered in current rates.
Rate Proceedings
Reference is made to Note 3 to each registrant's financial statements in Item 8
herein for a discussion of rate matters. For each registrant (except SAVANNAH),
such Note 3 includes a discussion of proceedings initiated by the FERC
concerning the reasonableness of the Southern electric system's wholesale rate
schedules and contracts that have a return on equity of 13.75% or greater.
For information regarding GEORGIA's Rocky Mountain Plant, including a joint
ownership agreement with OPC and a January 14, 1998, GPSC order relating to the
recovery of GEORGIA's costs in this plant, reference is made to Note 3 to
SOUTHERN's and to GEORGIA's financial statements in Item 8 herein.
Integrated Resource Planning
In 1991, the Georgia legislature passed certain legislation under which both
GEORGIA and SAVANNAH must file Integrated Resource Plans for approval by the
Georgia PSC. The plans must specify how GEORGIA and SAVANNAH each intends to
I-15
meet the future electrical needs of their customers through a combination of
demand-side and supply-side resources. The Georgia PSC must pre-certify these
new resources. Once certified, all prudently incurred construction costs and
purchased power costs will be recoverable through rates.
By orders issued in 1992 and by amended orders issued in 1995, the Georgia
PSC approved Integrated Resource Plans for both GEORGIA and SAVANNAH.
In March 1997, the Georgia PSC approved amendments to GEORGIA's 1995
Integrated Resource Plan. Pursuant to the amended plan, the Georgia PSC
certified a five-year purchase power agreement scheduled to begin in June 2000
for approximately 215 megawatts. Capacity and fixed operation and maintenance
payments over the five-year period are estimated to be approximately $39
million.
The Florida PSC set conservation goals and approved programs to accomplish
the goals beginning in 1995. The goals require conservation programs which
reduce 154 megawatts of summer peak demand and 65 million kilowatt-hours of
sales by the year 2004. For additional information, reference is made to GULF's
"Management's Discussion and Analysis - Future Earnings Potential" in Item 7
herein.
Environmental Cost Recovery Plans
GULF and MISSISSIPPI both have retail rate mechanisms that provide for recovery
of environmental compliance costs. For a description of these plans, see Note 3
to GULF's and MISSISSIPPI's financial statements in Item 8 herein.
Employee Relations
The companies of the SOUTHERN system had a total of 30,756 employees on their
payrolls at December 31, 1997.
------------------------------ --- -------------------------
Employees
at
December 31, 1997
-------------------------
ALABAMA 6,531
GEORGIA 8,354
GULF 1,328
MISSISSIPPI 1,245
SAVANNAH 535
SCS 3,222
Southern Energy* 6,089
Southern Nuclear 3,070
Other 382
------------------------------ --- -------------------------
Total 30,756
============================== === =========================
*Includes 5,709 employees on international payrolls.
The operating affiliates have separate agreements with local unions of the
IBEW generally covering wages, working conditions and procedures for handling
grievances and arbitration. These agreements apply with certain exceptions to
operating, maintenance and construction employees.
ALABAMA has agreements with the IBEW on a three-year contract extending to
August 15, 1998. Upon notice given at least 60 days prior to that date,
negotiations may be initiated with respect to agreement terms to be effective
after such date.
GEORGIA has an agreement with the IBEW covering wages and working
conditions, which is in effect through June 30, 1999.
GULF has an agreement with the IBEW on a three-year contract extending to
August 15, 1998. Upon notice given at least 60 days prior to that date,
negotiations may be initiated with respect to agreement terms to be effective
after such date.
MISSISSIPPI has an agreement with the IBEW on a three-year contract
extending to August 16, 1998. Upon notice given at least 60 days prior to that
date, negotiations may be initiated with respect to agreement terms to be
effective after such date.
I-16
SAVANNAH has three-year labor agreements with the IBEW and the Office and
Professional Employees International Union that expire April 16, 1999 and
December 1, 1999, respectively.
Southern Energy has a 5-year labor agreement with the IBEW extending to
October 31, 2002, and the United Paperworkers International Union extending to
June 1, 2002, covering employees of Mobile Energy. At its State Line facility in
Hammond, Indiana, Southern Energy has a labor contract with the United Steel
Workers that extends to January 1, 2004.
Southern Nuclear has agreements with the IBEW on separate three-year
contracts extending to August 15, 1998 for Plant Farley and to July 1, 1999 for
Plants Hatch and Vogtle. Upon notice given at least 60 days prior to these
dates, negotiations may be initiated with respect to agreement terms to be
effective after such dates.
Southern Nuclear also has an agreement with the United Plant Guard Workers
of America for security officers at Plant Hatch extending to September 3, 1998.
Upon notice given at least 60 days prior to that date, negotiations may be
initiated with respect to agreement terms to be effective after such date.
The agreements also subject the terms of the pension plans for the companies
discussed above to collective bargaining with the unions at five-year intervals.
I-17
Item 2. PROPERTIES
Electric Properties
The operating affiliates and SEGCO, at December 31, 1997, operated 33
hydroelectric generating stations, 32 fossil fuel generating stations and three
nuclear generating stations. The amounts of capacity owned by each company are
shown in the table below.
----------------------- -------------------------------------
Nameplate
Generating Station Location Capacity (1)
----------------------- ------------------- -----------------
(Kilowatts)
Fossil Steam
Gadsden Gadsden, AL 120,000
Gorgas Jasper, AL 1,221,250
Barry Mobile, AL 1,525,000
Chickasaw Chickasaw, AL 40,000
Greene County Demopolis, AL 300,000 (2)
Gaston Unit 5 Wilsonville, AL 880,000
Miller Birmingham, AL 2,532,288 (3)
---------
ALABAMA Total 6,618,538
---------
Arkwright Macon, GA 160,000
Atkinson Atlanta, GA 180,000
Bowen Cartersville, GA 3,160,000
Branch Milledgeville, GA 1,539,700
Hammond Rome, GA 800,000
McDonough Atlanta, GA 490,000
McManus Brunswick, GA 115,000
Mitchell Albany, GA 170,000
Scherer Macon, GA 750,924 (4)
Wansley Carrollton, GA 925,550 (5)
Yates Newnan, GA 1,250,000
---------
GEORGIA Total 9,541,174
---------
Crist Pensacola, FL 1,045,000
Lansing Smith Panama City, FL 305,000
Scholz Chattahoochee, FL 80,000
Daniel Pascagoula, MS 500,000 (6)
Scherer Unit 3 Macon, GA 204,500 (4)
-----------
GULF Total 2,134,500
---------
Eaton Hattiesburg, MS 67,500
Sweatt Meridian, MS 80,000
Watson Gulfport, MS 1,012,000
Daniel Pascagoula, MS 500,000 (6)
Greene County Demopolis, AL 200,000 (2)
-----------
MISSISSIPPI Total 1,859,500
-----------
----------------------- -----------------------------------------
Nameplate
Generating Station Location Capacity
-------------------- ------------------------- ------------------
(Kilowatts)
McIntosh Effingham County, GA 163,117
Kraft Port Wentworth, GA 281,136
Riverside Savannah, GA 102,278
-----------
SAVANNAH Total 546,531
-----------
Gaston Units 1-4 Wilsonville, AL
SEGCO Total 1,000,000 (7)
-----------
Total Fossil Steam 21,700,243
-----------
Nuclear Steam
Farley Dothan, AL
ALABAMA Total 1,720,000
-----------
Hatch Baxley, GA 862,669 (8)
Vogtle Augusta, GA 1,060,240 (9)
-----------
GEORGIA Total 1,922,909
----------
Total Nuclear Steam 3,642,909
-----------
Combustion Turbines
Greene County Demopolis, AL
ALABAMA Total 720,000
-----------
Arkwright Macon, GA 30,580
Atkinson Atlanta, GA 78,720
Bowen Cartersville, GA 39,400
Intercession City Intercession City, FL 47,333 (10)
McDonough Atlanta, GA 78,800
McIntosh
Units 1,2,3,4,7,8 Effingham County, GA 480,000
McManus Brunswick, GA 481,700
Mitchell Albany, GA 118,200
Robins Warner Robins, GA 160,000
Wilson Augusta, GA 354,100
Wansley Carrollton, GA 26,322 (5)
-----------
GEORGIA Total 1,895,155
---------
Lansing Smith
Unit A (GULF) Panama City, FL 39,400
Chevron Cogenerating
Station Pascagoula, MS 147,292 (11)
Sweatt Meridian, MS 39,400
Watson Gulfport, MS 39,360
---------
MISSISSIPPI Total 226,052
---------
Boulevard Savannah, GA 59,100
Kraft Port Wentworth, GA 22,000
McIntosh
Units 5&6 Effingham County, GA 160,000
SAVANNAH Total 241,100
----------------------------------------------- -----------------
I-18
------------------------- -------------------- -----------------
Nameplate
Generating Station Location Capacity
------------------------- -------------------- -----------------
(Kilowatts)
Gaston (SEGCO) Wilsonville, AL 19,680 (7)
Total Combustion Turbines 3,141,387
Hydroelectric Facilities
Weiss Leesburg, AL 87,750
Henry Ohatchee, AL 72,900
Logan Martin Vincent, AL 128,250
Lay Clanton, AL 177,000
Mitchell Verbena, AL 170,000
Jordan Wetumpka, AL 100,000
Bouldin Wetumpka, AL 225,000
Harris Wedowee, AL 135,000
Martin Dadeville, AL 154,200
Yates Tallassee, AL 32,000
Thurlow Tallassee, AL 58,000
Lewis Smith Jasper, AL 157,500
Bankhead Holt, AL 45,125
Holt Holt, AL 40,000
-----------
ALABAMA Total 1,582,725
----------
Barnett Shoals
(Leased) Athens, GA 2,800
Bartletts Ferry Columbus, GA 173,000
Goat Rock Columbus, GA 26,000
Lloyd Shoals Jackson, GA 14,400
Morgan Falls Atlanta, GA 16,800
North Highlands Columbus, GA 29,600
Oliver Dam Columbus, GA 60,000
Rocky Mountain Rome, GA 215,256 (12)
Sinclair Dam Milledgeville, GA 45,000
Tallulah Falls Clayton, GA 72,000
Terrora Clayton, GA 16,000
Tugalo Clayton, GA 45,000
Wallace Dam Eatonton, GA 321,300
Yonah Toccoa, GA 22,500
6 Other Plants 18,080
-----------
GEORGIA Total 1,077,736
----------
Total Hydroelectric Facilities 2,660,461
-----------
Total Generating Capacity 31,145,000
---------------------------------------------- -----------------
Notes:
(1) For additional information regarding facilities jointly-owned with
non-affiliated parties, see Item 2 - PROPERTIES -
"Jointly-Owned Facilities" herein.
(2) Owned by ALABAMA and MISSISSIPPI as
tenants in common in the proportions of 60% and 40%, respectively.
(3) Excludes the capacity owned by AEC.
(4) Capacity shown for GEORGIA is 8.4% of Units 1 and 2 and 75% of Unit 3.
Capacity shown for GULF is 25% of Unit 3.
(5) Capacity shown is GEORGIA's portion (53.5%) of total plant capacity.
(6) Represents 50% of the plant which is owned as tenants in common by
GULF and MISSISSIPPI.
(7) SEGCO is jointly-owned by ALABAMA and GEORGIA. (See Item 1 - BUSINESS
herein.)
(8) Capacity shown is GEORGIA's portion (50.1%) of total plant capacity.
(9) Capacity shown is GEORGIA's portion (45.7%) of total plant capacity.
(10) Capacity shown represents 33-1/3% of total plant capacity. GEORGIA
owns a 1/3 interest in the unit with 100% use of the
unit from June through September. FPC operates the unit.
(11) Generation is dedicated to a single industrial customer.
(12) Capacity shown is GEORGIA's portion (25.4%) of total plant capacity.
OPC operates the plant.
Except as discussed below under "Titles to Property," the principal plants
and other important units of the operating affiliates and SEGCO are owned in fee
by the respective companies. It is the opinion of management of each such
company that its operating properties are adequately maintained and are
substantially in good operating condition.
MISSISSIPPI owns a 79-mile length of 500-kilovolt transmission line which is
leased to Entergy Gulf States. The line, completed in 1984, extends from Plant
Daniel to the Louisiana state line. Entergy Gulf States is paying a use fee over
a forty-year period covering all expenses and the amortization of the original
$57 million cost of the line. At December 31, 1997, the unamortized portion of
this cost was $38 million.
The all-time maximum demand on the operating affiliates and SEGCO was
27,419,700 kilowatts and occurred in August 1995. This amount excludes demand
served by capacity retained by MEAG and Dalton and excludes demand associated
with power purchased from OPC and SEPA by its preference customers. At that
time, 29,596,100 kilowatts were supplied by SOUTHERN system generation and
2,176,400 kilowatts (net) were sold to other parties through net purchased and
interchanged power. The reserve margin for the operating affiliates and SEGCO at
I-19
that time was 9.4%. For additional information on peak demands, reference is
made to Item 6 - SELECTED FINANCIAL DATA herein.
ALABAMA and GEORGIA will incur significant costs in decommissioning their
nuclear units at the end of their useful lives. (See Item 1 - BUSINESS
"Regulation - Atomic Energy Act of 1954" and Note 1 to SOUTHERN's, ALABAMA's and
GEORGIA's financial statements in Item 8 herein.)
Other Electric Generation Facilities
Through special purpose subsidiaries, SOUTHERN owns interests in or operates
independent power production facilities and foreign utility companies. The
generating capacity of these utilities (or facilities) at December 31, 1997, was
as follows:
I-20
Jointly-Owned Facilities
ALABAMA and GEORGIA have sold and GEORGIA has purchased undivided interests in
certain generating plants and other related facilities to or from non-affiliated
parties. The percentages of ownership resulting from these transactions are as
follows:
ALABAMA and GEORGIA have contracted to operate and maintain the respective
units in which each has an interest (other than Rocky Mountain and Intercession
City, as described below) as agent for the joint owners.
In connection with the joint ownership arrangements for Plant Vogtle,
GEORGIA made commitments to purchase portions of OPC's and MEAG's capacity and
energy from this plant. Declining commitments were in effect during periods of
up to seven years following commercial operation and ended in 1996. In addition,
the Company has commitments regarding a portion of a 5 percent interest in Plant
Vogtle owned by MEAG that are in effect until the later of 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 any capacity
is available. The energy cost is a function of each unit's variable operating
costs. Except for the portion of the capacity payments related to the 1987 and
1990 write-offs of Plant Vogtle costs, the cost of such capacity and energy is
included in purchased power from non-affiliates in GEORGIA's Statements of
Income in Item 8 herein.
In December 1988, GEORGIA and OPC entered into a joint ownership agreement
for the Rocky Mountain plant under which GEORGIA agreed to retain its present
investment in the project and OPC agreed to finance, complete and operate the
facility. In 1995, the plant went into commercial operation. GEORGIA's ownership
is 25.4 percent. On January 14, 1998, the GPSC ordered that the Company be
allowed approximately $108 million of its $143 million investment in the plant
in rate base as of December 31, 1998. GEORGIA has appealed the GPSC's order. If
I-21
such order is ultimately upheld, GEORGIA will be required to record a charge to
earnings currently estimated at approximately $29 million, after taxes.
Reference is made to Note 3 to SOUTHERN's and GEORGIA's financial statements in
Item 8 herein for additional information regarding the Rocky Mountain plant.
In 1994, GEORGIA and FPC entered into a joint ownership agreement regarding
the Intercession City combustion turbine unit. The unit began commercial
operation in January 1997, and is operated by FPC. GEORGIA owns a one-third
interest in the unit, with use of 100% of the capacity from June through
September. FPC has the capacity the remainder of the year.
Sale of Property
Reference is made to Note 6 to GEORGIA's financial statements in Item 8 herein
for information regarding the sale completed in 1995 of GEORGIA's remaining
ownership interest in Plant Scherer Unit 4.
Titles to Property
The operating affiliates' and SEGCO's interests in the principal plants (other
than certain pollution control facilities, one small hydroelectric generating
station leased by GEORGIA and the land on which five combustion turbine
generators of MISSISSIPPI are located, which is held by easement) and other
important units of the respective companies are owned in fee by such companies,
subject only to the liens of applicable mortgage indentures (except for SEGCO)
and to excepted encumbrances as defined therein. The operating affiliates own
the fee interests in certain of their principal plants as tenants in common.
(See Item 2 - PROPERTIES - "Jointly-Owned Facilities" herein.) Properties such
as electric transmission and distribution lines and steam heating mains are
constructed principally on rights-of-way which are maintained under franchise or
are held by easement only. A substantial portion of lands submerged by
reservoirs is held under flood right easements. In substantially all of its coal
reserve lands, SEGCO owns or will own the coal only, with adequate rights for
the mining and removal thereof.
Property Additions and Retirements
During the period from January 1, 1993 to December 31, 1997, the operating
affiliates, SEGCO, SCS, Southern Nuclear, Southern Communications and Southern
Energy recorded gross property additions and retirements as follows:
----------------------- ------------------- --- ----------
Gross Property
Additions Retirements
--------------- -------------
(in millions)
ALABAMA $2,402 $ 415
GEORGIA (1) 2,697 1,534
GULF 336 138
MISSISSIPPI 428 91
SAVANNAH 178 17
SEGCO 29 8
SCS 99 131
Southern Nuclear 6 7
Southern
Communications 246 -
Southern Energy 1,039 38
Other 6 -
==========================================================
SOUTHERN system $7,466 $2,379
==========================================================
Notes:
(1) Includes approximately $446 million attributable to 1993 through 1997
sales of Plant Scherer Unit 4 to FP&L and JEA.
I-22
Item 3. LEGAL PROCEEDINGS
(1) SOUTHERN and Subsidiaries v. Commissioner of the IRS
(U.S. Tax Court)
Reference is made to Note 3 to SOUTHERN's, ALABAMA's, and GEORGIA's
financial statements in Item 8 herein under the captions "Southern
Company Tax Litigation", "Tax Litigation", and "Tax Litigation",
respectively.
(2) Frost v. ALABAMA
(Circuit Court of Jefferson County, Alabama)
Reference is made to Note 3 to SOUTHERN's and ALABAMA's financial
statements in Item 8 herein under the captions "Alabama Power Appliance
Warranty Litigation" and "Appliance Warranty Litigation", respectively.
(3) GEORGIA has been designated as a potentially responsible party under the
Comprehensive Environmental Response, Compensation and Liability Act with
respect to a site in Brunswick, Georgia.
Reference is made to Note 3 to SOUTHERN's and GEORGIA's financial
statements in Item 8 herein under the captions "Georgia Power Potentially
Responsible Party Status" and "Certain Environmental Contingencies,"
respectively.
See Item 1 - BUSINESS - "Construction Programs," "Fuel Supply," "Regulation
- Federal Power Act" and "Rate Matters" as well as Note 3 to each registrant's
financial statements in Item 8 herein for a description of certain other
administrative and legal proceedings discussed therein.
Additionally, each of the operating affiliates, Southern Energy, SCS,
Southern Nuclear, Energy Solutions and Southern Communications are, in the
normal course of business, engaged in litigation or administrative proceedings
that include, but are not limited to, acquisition of property, injuries and
damages claims, and complaints by present and former employees.
Item 4. SUBMISSION OF MATTERS TO A
VOTE OF SECURITY HOLDERS
ALABAMA, GEORGIA, GULF AND MISSISSIPPI each held special meetings of their
shareholders on December 10, 1997, for the purpose of amending their respective
charters. The amendments eliminate restrictions on each of these registrant's
ability to (1) issue unsecured indebtedness, (2) sell assets, merge or
consolidate without preferred shareholder approval under certain circumstances,
and (3) pay dividends on common stock.
The vote in connection with such matters was as follows:
FOR ABSTAINED from or AGAINST
ALABAMA 2,373,283 85,507
GEORGIA 2,601,807 52,487
GULF 437,296 5,394
MISSISSIPPI 328,961 16,340
I-23
EXECUTIVE OFFICERS OF SOUTHERN
(Identification of executive officers of SOUTHERN is inserted in Part I in
accordance with Regulation S-K, Item 401(b), Instruction 3.) The ages of the
officers set forth below are as of December 31, 1997.
A. W. Dahlberg
Chairman, President and Chief Executive Officer
Age 57
Elected in 1985; President and Chief Executive
Officer of GEORGIA from 1988 through 1993. He was elected President of SOUTHERN
effective January 1994. He was elected Chairman and Chief Executive Officer
effective March 1995.
Paul J. DeNicola
Executive Vice President and Director
Age 49
Elected in 1989; Executive Vice President of SOUTHERN since 1991. Elected
President and Chief Executive Officer of SCS effective January 1994. He
previously served as Executive Vice President of SCS from 1991 to 1993.
H. Allen Franklin
Executive Vice President and Director
Age 53
Elected in 1988; President and Chief Executive Officer
of SCS from 1988 through 1993 and, beginning 1991, Executive Vice President of
SOUTHERN. He was elected President and Chief Executive Officer of GEORGIA
effective January 1994.
Elmer B. Harris
Executive Vice President and Director
Age 58
Elected in 1989; President and Chief Executive Officer
of ALABAMA since 1989 and, beginning 1991, Executive Vice President of SOUTHERN.
David M. Ratcliffe
Senior Vice President
Age 49
Elected in 1995; President and Chief Executive Officer of MISSISSIPPI from 1991
to 1995. He also serves as Executive Vice President of SCS beginning in 1995.
Effective March 1, 1998, elected Executive Vice President and Treasurer of
GEORGIA.
W. L. Westbrook
Financial Vice President, Chief Financial Officer and Treasurer
Age 58
Elected in 1986; responsible primarily for all aspects of financing for
SOUTHERN. He has served as Executive Vice President of SCS since 1986.
Thomas G. Boren
Vice President
Age 48
Elected in 1995; President and Chief Executive Officer of Southern Energy since
1992.
Bill M. Guthrie
Vice President
Age 64
Elected in 1991; serves as Chief Production Officer for the SOUTHERN system.
Senior Executive Vice President of SCS effective January 1994 and Executive Vice
President of ALABAMA since 1988. He also serves as Executive Vice President of
GEORGIA and Vice President of GULF, MISSISSIPPI and SAVANNAH.
W. G. Hairston, III
Age 53
President and Chief Executive Officer of Southern Nuclear since 1993. He
previously served as Executive Vice President of GEORGIA from 1989 to March
1997.
Stephen A. Wakefield
Senior Vice President and General Counsel
Age 57
Elected in 1997. Previously, he was a partner at the firm of Akin, Gump,
Strauss, Hauer & Feld, LLP from July 1991 through August 10, 1997.
Each of the above is currently an officer of SOUTHERN, serving a term
running from the last annual meeting of the directors (May 28, 1997) for one
year until the next annual meeting or until his successor is elected and
qualified, except for Mr.Wakefield who was elected on August 11, 1997.
I-24
PART II
Item 5. MARKET FOR REGISTRANTS' COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
(a) The common stock of SOUTHERN is listed and traded on the New York
Stock Exchange. The stock is also traded on regional exchanges across
the United States. High and low stock prices, per the New York Stock
Exchange Composite Tape during each quarter for the past two years
were as follows:
---------------------- ----------- --------- --------
High Low
----------- --------
1997
First Quarter $23-3/8 $20-3/4
Second Quarter 22-1/4 19-7/8
Third Quarter 23 20-13/16
Fourth Quarter 26-1/4 22
1996
First Quarter $25-7/8 $22-3/8
Second Quarter 24-5/8 21-1/4
Third Quarter 24-5/8 21-3/4
Fourth Quarter 23-1/8 21-1/8
------------------ --------------- --- --------------
There is no market for the other registrants' common stock, all of
which is owned by SOUTHERN. On February 28, 1998, the closing price
of SOUTHERN's common stock was $24.6875.
(b) Number of SOUTHERN's common stockholders at December 31, 1997:
200,508
Each of the other registrants have one common stockholder, SOUTHERN.
(c) Dividends on each registrant's common stock are payable at the
discretion of their respective board of directors. The dividends on
common stock paid and/or declared by SOUTHERN and the operating
affiliates to their stockholder(s) for the past two years were as
follows: (in thousands)
----------------- --------- ------------- ----------
Registrant Quarter 1997 1996
----------------- --------- ------------- ----------
SOUTHERN First $220,194 $211,081
Second 221,544 211,272
Third 222,980 212,200
Fourth 224,287 212,201
ALABAMA First 80,100 76,000
Second 85,600 76,400
Third 86,100 76,400
Fourth 87,800 118,700
GEORGIA First 122,700 121,500
Second 131,000 122,100
Third 131,800 122,100
Fourth 134,500 109,800
GULF First 12,900 12,300
Second 13,800 12,400
Third 13,800 12,400
Fourth 24,100 21,200
MISSISSIPPI First 11,300 10,600
Second 12,100 10,700
Third 12,200 10,600
Fourth 13,800 12,000
SAVANNAH First 5,100 4,800
Second 5,400 4,800
Third 5,500 4,800
Fourth 4,500 5,200
----------------- --------- ------------- ----------
The dividend paid per share by SOUTHERN was 31.5(cent) for each quarter of
1996 and 32.5(cent) for each quarter of 1997. The dividend paid on SOUTHERN's
common stock for the first quarter of 1998 was raised to 33.5(cent) per share.
II-1
The amount of dividends on their common stock that may be paid by the
subsidiary registrants is restricted in accordance with their first mortgage
bond indenture and, in the case of SAVANNAH, its charter. The amounts of
earnings retained in the business and the amounts restricted against the payment
of cash dividends on common stock at December 31, 1997, were as follows:
------------------ ------------------ --- --------------
Retained Restricted
Earnings Amount
------------------ --------------
(in millions)
ALABAMA $1,221 $ 796
GEORGIA 1,745 897
GULF 172 127
MISSISSIPPI 170 118
SAVANNAH 113 68
Consolidated 3,842 2,024
------------------ ------------------ --- --------------
Item 6. SELECTED FINANCIAL DATA
SOUTHERN. Reference is made to information under the heading "Selected
Consolidated Financial and Operating Data," contained herein
at pages II-41 through II-54.
ALABAMA. Reference is made to information under the heading "Selected
Financial and Operating Data," contained herein at pages II-83
through II-96.
GEORGIA. Reference is made to information under the heading "Selected
Financial and Operating Data," contained herein at pages II-129
through II-143.
GULF. Reference is made to information under the heading "Selected
Financial and Operating Data," contained herein at pages II-172 through
II-185.
MISSISSIPPI. Reference is made to information under the heading "Selected
Financial and Operating Data," contained herein at pages II-212
through II-225.
SAVANNAH. Reference is made to information under the heading "Selected
Financial and Operating Data," contained herein at pages II-247
through II-259.
Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND
FINANCIAL CONDITION
SOUTHERN. Reference is made to information under the heading "Management's
Discussion and Analysis of Results of Operations and Financial Condition,"
contained herein at pages II-8 through II-16.
ALABAMA. Reference is made to information under the heading "Management's
Discussion and Analysis of Results of Operations and Financial Condition,"
contained herein at pages II-58 through II-64.
GEORGIA. Reference is made to information under the heading "Management's
Discussion and Analysis of Results of Operations and Financial Condition,"
contained herein at pages II-100 through II-107.
GULF. Reference is made to information under the heading "Management's
Discussion and Analysis of Results of Operations and Financial Condition,"
contained herein at pages II-147 through II-154.
MISSISSIPPI. Reference is made to information under the heading "Management's
Discussion and Analysis of Results of Operations and Financial Condition,"
contained herein at pages II-189 through II-195.
SAVANNAH. Reference is made to information under the heading "Management's
Discussion and Analysis of Results of Operations and Financial Condition,"
contained herein at pages II-229 through II-234.
Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Reference is made to information in SOUTHERN's "Management's Discussion and
Analysis - Derivative Financial Instruments" and to Note 1 to SOUTHERN's
financial statements under the headings "Financial Instruments for Non-Trading"
and "Financial Instruments for Trading" contained herein on pages II-13 through
II-14; and pages II-26 through II-28, respectively.
II-2
II-4
THE SOUTHERN COMPANY
AND SUBSIDIARY COMPANIES
FINANCIAL SECTION
II-5
MANAGEMENT'S REPORT
Southern Company and Subsidiary Companies 1997 Annual Report
The management of Southern Company has prepared -- and is responsible for -- the
consolidated financial statements and related information included in this
report. These statements were prepared in accordance with generally accepted
accounting principles appropriate in the circumstances and necessarily include
amounts that are based on the best estimates and judgments of management.
Financial information throughout this annual report is consistent with the
financial statements.
The company maintains a system of internal accounting controls to provide
reasonable assurance that assets are safeguarded and that books and records
reflect only authorized transactions of the company. Limitations exist in any
system of internal controls, however, based on a recognition that the cost of
the system should not exceed its benefits. The company believes its system of
internal accounting controls maintains an appropriate cost/benefit relationship.
The company's system of internal accounting controls is evaluated on an
ongoing basis by the company's internal audit staff. The company's independent
public accountants also consider certain elements of the internal control system
in order to determine their auditing procedures for the purpose of expressing an
opinion on the financial statements.
The audit committee of the board of directors, composed of five directors
who are not employees, provides a broad overview of management's financial
reporting and control functions. Periodically, this committee meets with
management, the internal auditors, and the independent public accountants to
ensure that these groups are fulfilling their obligations and to discuss
auditing, internal controls, and financial reporting matters. The internal
auditors and independent public accountants have access to the members of the
audit committee at any time.
Management believes that its policies and procedures provide reasonable
assurance that the company's operations are conducted according to a high
standard of business ethics.
In management's opinion, the consolidated financial statements present
fairly, in all material respects, the financial position, results of operations,
and cash flows of Southern Company and its subsidiary companies in conformity
with generally accepted accounting principles.
/s/A. W. Dahlberg
A. W. Dahlberg
Chairman, President, and Chief Executive Officer
/s/W. L. Westbrook
W. L. Westbrook
Financial Vice President, Chief Financial Officer,
and Treasurer
February 11, 1998
II-6
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors and to the Stockholders of Southern Company:
We have audited the accompanying consolidated balance sheets and consolidated
statements of capitalization of Southern Company (a Delaware corporation) and
subsidiary companies as of December 31, 1997 and 1996, and the related
consolidated statements of income, retained earnings, paid-in capital, and cash
flows for each of the three years in the period ended December 31, 1997. 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 consolidated financial statements (pages 11-17 through
11-40) referred to above present fairly, in all material respects, the financial
position of Southern Company and subsidiary companies as of December 31, 1997
and 1996, and the results of their operations and their cash flows for each of
the three years in the period ended December 31, 1997, in conformity with
generally accepted accounting principles.
/s/Arthur Andersen LLP
Atlanta, Georgia
February 11, 1998
II-7
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL
CONDITION
Southern Company and Subsidiary Companies 1997 Annual Report
RESULTS OF OPERATIONS
Earnings and Dividends
Southern Company reported 1997 earnings of $972 million or $1.42 for both basic
and diluted earnings per share. The traditional core business of selling
electricity in the southeastern United States remained strong, while
non-traditional business results were adversely affected by a $111 million,
after taxes, windfall profits tax assessed against South Western Electricity
(SWEB) in the United Kingdom. SWEB is a subsidiary of Southern Energy, Inc.
(Southern Energy). Excluding the windfall profits tax, Southern Energy's
earnings account for 10 percent of consolidated net income in 1997.
Consolidated net income decreased by $155 million compared with the amount
reported for 1996. Continued cost controls and steady demand for electricity
were offset by increased financing costs for the non-traditional business and
the windfall profits tax.
Costs related to work force reduction programs decreased earnings by $31
million or 5 cents per share and $53 million or 8 cents per share in 1997 and
1996, respectively. These costs are expected to be recovered through future
savings in approximately two years following each program's implementation.
In 1996, earnings were $1.1 billion or $1.68 for both basic and diluted
earnings per share -- up 2 cents from the per share amount reported in 1995.
Earnings in 1996, when compared with 1995 results, were affected by increased
energy sales and growth in the non-traditional business.
Dividends paid on common stock during 1997 were $1.30 per share or 321/2
cents per quarter. During 1996 and 1995, dividends paid per share were $1.26 and
$1.22, respectively. In January 1998, the Southern Company raised the quarterly
dividend to 331/2 cents per share or an annual rate of $1.34 per share.
Acquisitions
Southern Energy owns and manages international and domestic non-traditional
electric power production and delivery facilities for Southern Company. Southern
Energy's acquisitions of 100 percent of Consolidated Electric Power Asia (CEPA)
and a 26 percent interest in a German utility were completed in 1997. Also,
Southern Energy acquired SWEB in late 1995. These businesses have been included
in the consolidated financial statements since the dates of acquisition and are
not reflected in prior periods. As a result, changes in revenues and expenses
for Southern Energy in 1997 and 1996 reflect significant amounts related to
acquisitions, which were not fully reflected in each year being compared.
Therefore, to facilitate discussing the results of operations for business
segments, Southern Energy's variances are primarily driven by the above reason
unless otherwise noted.
Revenues
Operating revenues increased in 1997 and 1996 as a result of the following
factors:
Increase (Decrease)
From Prior Year
---------------------------------
1997 1996 1995
---------------------------------
Retail -- (in millions)
Growth and price
change $ 105 $ 124 $ 177
Weather (110) (64) 143
Fuel cost recovery and
other (13) 2 134
---------------------------------------------------------------
Total retail (18) 62 454
---------------------------------------------------------------
Sales for resale --
Within service area (28) 10 39
Outside service area 76 14 (90)
---------------------------------------------------------------
Total sales for resale 48 24 (51)
Southern Energy 2,154 1,040 458
Other operating revenues 69 52 22
---------------------------------------------------------------
Total operating revenues $2,253 $1,178 $ 883
===============================================================
Percent change 21.8% 12.8% 10.6%
---------------------------------------------------------------
Retail revenues of $7.6 billion declined slightly compared with last year.
Continued growth in the traditional service area was offset by the negative
impact of weather on energy sales and by industrial and commercial customers
taking advantage of lower load management rates. This trend will probably
continue as the utility industry becomes much more competitive. In 1996, retail
revenues barely increased by 0.8 percent compared with the year 1995. Under fuel
cost recovery provisions, fuel revenues generally equal fuel expense --
including the fuel component of purchased energy -- and do not affect net
income.
Sales for resale revenues within the service area were $381 million in 1997,
down 7.1 percent from the prior year. This decrease resulted primarily from
supplying less electricity under contractual agreements with certain wholesale
customers in 1997. Revenues from sales for resale within the service area were
II-8
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 1997 Annual Report
$409 million in 1996, up 2.5 percent from the prior year.
Revenues from sales to utilities outside the service area under long-term
contracts consist of capacity and energy components. Capacity revenues reflect
the recovery of fixed costs and a return on investment under the contracts.
Energy is generally sold at variable cost. The capacity and energy components
were as follows:
1997 1996 1995
------------------------------------
(in millions)
Capacity $203 $217 $237
Energy 183 176 151
---------------------------------------------------------
Total $386 $393 $388
=========================================================
Capacity revenues decreased in 1997 and 1996 because the amount of capacity
under contract declined slightly during 1996. Additional declines in capacity
are not scheduled until after 1999.
Southern Energy's revenues have escalated to $3.8 billion and $1.7 billion
in 1997 and 1996, respectively. These rapid increases are primarily attributable
to the development and growth of energy trading and marketing activities,
primarily in 1997. Also, revenues have increased as a result of international
acquisitions. In 1997, energy trading and marketing revenues increased $1.9
billion compared with amounts recorded in 1996. However, these revenues were
substantially offset by purchased power expenses incurred in completing these
trading and marketing transactions. Energy trading and marketing -- similar to
other low margin sales activities -- is dependent on huge volumes for
profitability.
Changes in traditional core business revenues are influenced heavily by the
amount of energy sold each year. Kilowatt-hour sales for 1997 and the percent
change by year were as follows:
(billions of
kilowatt-hours) Amount Percent Change
---------- ----------------------------
1997 1997 1996 1995
---------- ----------------------------
Residential 39.2 (2.2)% 2.5% 9.2%
Commercial 38.9 2.5 5.7 5.5
Industrial 54.2 2.6 2.2 2.7
Other 0.9 (1.1) 5.7 2.1
----------
Total retail 133.2 1.1 3.3 5.4
Sales for resale --
Within service area 9.9 (9.6) 15.4 16.2
Outside service area 13.3 23.6 17.9 (15.1)
----------
Total 156.4 1.9 5.0 4.4
===================================================================
The rate of increase in 1997 retail energy sales was significantly lower
than the past two years. Although the total number of residential customers
served increased by 63,000 during the year, residential energy sales experienced
a decline as a result of milder weather in 1997, compared with closer to normal
weather in 1996. Commercial and industrial sales both in 1997 and 1996 continued
to show slight gains in excess of the national averages. This reflects the
strength of business and economic conditions in Southern Company's traditional
service area. Energy sales to retail customers are projected to increase at an
average annual rate of 2.1 percent during the period 1998 through 2008.
Energy sales for resale outside the service area are predominantly unit
power sales under long-term contracts to Florida utilities. Economy sales and
amounts sold under short-term contracts are also sold for resale outside the
service area. Sales to customers outside the service area increased in both 1997
and 1996 and declined in 1995 when compared with the respective prior year.
However, these fluctuations in energy sales under long-term contracts have
minimal effect on earnings because Southern Company is paid for dedicating
specific amounts of its generating capacity to these utilities outside the
service area.
Expenses
Total operating expenses of $10.7 billion for 1997 increased $2.2 billion
compared with the prior year. Traditional core business expenses increased $69
million. Southern Energy's expenses increased almost $2.1 billion. The sharp
increase for Southern Energy resulted primarily from two factors. First, the
acquisition of CEPA is reflected only in 1997 expenses. Second, nearly $1.9
billion relates to energy trading and marketing activities, which is included in
purchased power expenses. The costs to produce and deliver electricity for the
traditional core business in 1997 increased by $37 million to meet higher energy
demands. Also, costs related to work force reduction programs decreased in 1997
by $35 million. Traditional core business depreciation expenses and taxes other
than income taxes increased by $158 million as a result of additional utility
plant being placed into service and increased accelerated depreciation of
certain assets.
In 1996, operating expenses of $8.5 billion increased 16.6 percent compared
with 1995. Traditional core business expenses increased $173 million. Southern
Energy's expenses increased $976 million. The large increase for Southern Energy
resulted primarily from SWEB, which was acquired in late 1995. The costs to
II-9
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 1997 Annual Report
produce and deliver electricity for the traditional core business in 1996
increased by $79 million to meet higher energy demands. Also, costs related to
work force reduction programs increased expenses by $58 million compared with
such expenses in 1995. Depreciation expense and taxes other than income taxes
increased $39 million.
Fuel costs constitute the single largest expense for Southern Company's
traditional core business. 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 --
within the core business service area -- were as follows:
1997 1996 1995
--------------------------
Total generation
(billions of kilowatt-hours) 160 156 147
Sources of generation
(percent) --
Coal 77 77 77
Nuclear 17 17 17
Hydro 4 4 4
Oil and gas 2 2 2
Average cost of fuel per net
kilowatt-hour generated
(cents) --
Coal 1.63 1.65 1.73
Nuclear 0.53 0.52 0.56
Total 1.46 1.48 1.53
--------------------------------------------------------------
Total fuel and purchased power expenses of $5.3 billion in 1997 increased
$2.0 billion compared with the prior year. These expenses for traditional core
business increased $32 million and, Southern Energy's portion increased $1.9
billion. The traditional core business's customer demand for electricity rose by
1.6 billion kilowatt-hours more than in 1996. The additional cost to meet the
demand was offset slightly by a lower average cost of fuel per net kilowatt-hour
generated. Southern Energy's increase in expenses escalated as a result of
energy trading and marketing activities discussed earlier. Fuel and purchased
power costs of $3.3 billion in 1996 increased $731 million compared with 1995.
Traditional core business increased $49 million and Southern Energy increased
$682 million because of the acquisition of SWEB in late 1995.
Excluding the windfall profits tax in the United Kingdom, total income taxes
in 1997 declined by $66 million compared with the amount in 1996. Southern
Energy's portion was a reduction of $37 million. For 1996, traditional core
business income taxes decreased $40 million, and Southern Energy increased $41
million.
Total net interest charges and capital and preferred stock expenses
increased $248 million from amounts reported in the previous year. These costs
for traditional core business overall netted out to be nearly flat compared with
the reported amounts in 1996. Southern Energy's costs increased $221 million
related primarily to financing acquisitions. In 1996, these same costs for
traditional core business declined by $69 million, but Southern Energy's
interest charges increased $85 million. The decline in costs for core business
was attributable to lower interest rates and continued refinancing activities in
1996. As a result of favorable market conditions, $1.7 billion in 1997, $574
million in 1996, and $1.1 billion in 1995 of traditional senior securities were
issued for the primary purpose of retiring higher-cost securities.
Effects of Inflation
Southern Company's traditional core business 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 Southern Company because of the large investment in long-lived utility
plant. Conventional accounting for historical cost does not recognize this
economic loss nor the partially offsetting gain that arises through financing
facilities with fixed-money obligations such as long-term debt and preferred
stock. Any recognition of inflation by regulatory authorities is reflected in
the rate of return allowed.
Future Earnings Potential
The results of operations for the past three years are not necessarily
indicative of future earnings potential. The level of Southern Company's future
earnings depends on numerous factors. Two major factors are: achieving energy
sales growth in a less regulated, more competitive environment; and operating
non-traditional business activities successfully.
II-10
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 1997 Annual Report
Southern Company continues to position its business to meet the challenges of
a new competitive environment. Work force reduction programs have reduced
earnings by $31 million, $53 million, and $17 million for the years 1997, 1996,
and 1995, respectively. These actions -- in conjunction with other cost
containment programs -- will assist efforts to continue being a low-cost
provider of electricity.
The operating companies currently operate as vertically integrated companies
providing electricity to customers within the traditional service area of the
southeastern United States. Prices for electricity provided by the operating
companies to retail customers are set by state public service commissions under
cost-based regulatory principles.
Rates for Alabama Power and Mississippi Power are adjusted periodically
within certain limitations based on earned retail rate of return compared with
an allowed return. Georgia Power is required to file a general rate case by July
1, 1998. See Note 3 to the financial statements for information about other
retail and wholesale regulatory matters.
Future earnings for the operating companies in the near term will depend upon
growth in energy sales, which is subject to a number of factors. These factors
include weather, competition, changes in contracts with neighboring utilities,
energy conservation practiced by customers, the elasticity of demand, and the
rate of economic growth in the company's service area.
The electric utility industry in the United States is currently undergoing a
period of dramatic change as a result of regulatory and competitive factors.
Among the primary agents of change has been the Energy Policy Act of 1992
(Energy Act). The Energy Act allows independent power producers (IPPs) to access
a utility's transmission network in order to sell electricity to other
utilities. This enhances the incentive for IPPs to build cogeneration plants for
a utility's large industrial and commercial customers and sell energy generation
to other utilities. Also, electricity sales for resale rates are being driven
down by wholesale transmission access and numerous potential new energy
suppliers, including power marketers and brokers. Southern Company is
aggressively working to maintain and expand its share of wholesale sales in the
Southeastern power markets.
Although the Energy Act does not permit retail customer access, it was a
major catalyst for the current restructuring and consolidation taking place
within the utility industry. Numerous federal and state initiatives are in
varying stages to promote wholesale and retail competition. Among other things,
these initiatives allow customers to choose their electricity provider. As these
initiatives materialize, the structure of the utility industry could radically
change. Some states have approved initiatives that result in a separation of the
ownership and/or operation of generating facilities from the ownership and/or
operation of transmission and distribution facilities. While various
restructuring and competition initiatives have been or are being discussed in
Alabama, Florida, Georgia, and Mississippi, none have been enacted to date.
Enactment would require numerous issues to be resolved, including significant
ones relating to transmission pricing and recovery of any stranded investments.
The inability of an operating company to recover its investments, including the
regulatory assets described in Note 1 to the financial statements, could have a
material adverse effect on the financial condition of that operating company.
The operating companies are attempting to minimize or reduce their cost
exposure. See Note 3 to the financial statements for information regarding these
efforts.
Continuing to be a low-cost producer could provide opportunities to increase
market share and profitability in markets that evolve with changing regulation.
Conversely, unless Southern 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.
To adapt to a less regulated, more competitive environment, Southern Company
continues to evaluate and consider a wide array of potential business
strategies. These strategies may include business combinations, acquisitions
involving other utility or non-utility businesses or properties, internal
restructuring, disposition of certain assets, or some combination thereof.
Furthermore, Southern Company may engage in other new business ventures that
arise from competitive and regulatory changes in the utility industry. Pursuit
of any of the above strategies, or any combination thereof, may significantly
affect the business operations and financial condition of Southern Company.
The Energy Act amended the Public Utility Holding Company Act of 1935
(PUHCA). The amendment allows holding companies to form exempt wholesale
generators and foreign utility companies to sell power largely free of
regulation under PUHCA. These entities are able to sell power to affiliates --
under certain restrictions -- and to own and operate power generating facilities
in other domestic and international markets. To take advantage of existing and
II-11
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 1997 Annual Report
evolving opportunities, Southern Energy -- founded in 1981 -- is focused on
several key international and domestic business lines, including energy
distribution, integrated utilities, stand-alone generation, and other
energy-related products and services. As the energy marketplace evolves,
Southern Energy is positioning the company to become a major competitor in
energy trading and marketing activities. As part of this strategy, Southern
Energy entered into a joint venture with Vastar Resources effective in January
1998. The two companies combined their energy trading and marketing operations
to form a new full-service energy provider, Southern Company Energy Marketing.
Also, Southern Energy is expanding its international business through
acquisitions. In September 1997, Southern Energy acquired a 26 percent interest
in a German utility for approximately $820 million. Also, the acquisition of
CEPA for a total net investment of some $2.1 billion was completed in mid-1997.
In late 1995, SWEB was acquired for approximately $1.8 billion. In July 1996, a
25 percent interest in SWEB was sold. For additional information on
acquisitions, see Note 14 to the financial statements.
The CEPA acquisition has a slightly dilutive impact on earnings in the near
term. However, Southern Energy's investments should strengthen the opportunities
for Southern Company's long-term future earnings growth. At December 31, 1997,
Southern Energy's total assets amounted to $11 billion.
The depreciation of southeast Asian currencies is likely to increase the
cost of electricity that nationally owned utilities purchase from independent
power projects relative to the prices received by those utilities from their
customers. This could cause a deterioration in the financial condition of
nationally owned utilities, which could potentially impact these
utilities' ability to meet their obligations under existing contracts and could
reduce the near-term opportunities for greenfield independent power projects in
the region. However, fewer greenfield opportunities may, to some extent, be
offset by increased opportunities for CEPA to acquire projects from regional
developers who have been adversely affected by the financial crisis, and also
by a possible increase in the pace of privatizations by regional governments
needing to raise capital.
Also during 1997, there was a substantial depreciation of the Philippine
peso relative to the U.S. dollar. However, the long-term power sales contracts
that govern CEPA's revenues from existing projects in the Philippines provide
for U.S. dollar payments, or indexing to the U.S. dollar. This should
sufficiently cover foreign currency costs of operation, including debt service
and return on and of capital. The National Power Corporation, whose obligations
are guaranteed by the Republic of the Philippines, is the counterparty to these
contracts.
The staff of the Securities and Exchange Commission (SEC) has questioned
certain of the current accounting practices of the electric utility industry --
including Southern Company's -- regarding the recognition, measurement, and
classification of decommissioning costs for nuclear generating facilities in the
financial statements. In response to these questions, the Financial Accounting
Standards Board (FASB) has decided to review the accounting for liabilities
related to closure and removal of long-lived assets, including nuclear
decommissioning. If the FASB issues new accounting rules, the estimated costs
of closing and removing Southern Company's nuclear and other facilities may be
required to be recorded as liabilities in the Consolidated Balance Sheets.
Also, the annual provisions for such costs could change. Because of the
company's current ability to recover closure and removal costs through rates,
these changes would not have a significant adverse effect on results of
operations. See Note 1 to the financial statements under "Depreciation and
Nuclear Decommissioning" for additional information.
Southern Company is heavily dependent upon complex computer systems for all
phases of its operations. The year 2000 issue --common to most corporations --
concerns the inability of certain software and databases to properly recognize
date-sensitive information related to the year 2000 and thereafter. This problem
could result in a material disruption to the company's operations, if not
corrected. Southern Company has assessed and developed a detailed strategy to
prevent or at least minimize problems related to the year 2000 issue. In 1997,
resources were committed and implementation began to modify the affected
information systems. Total costs related to the project are estimated to be
approximately $85 million, of which $8 million was spent in 1997. Most all
remaining costs will be expensed in 1998. Implementation is currently on
schedule. Although the degree of success of this project cannot be determined at
this time, management believes there will be no significant effect on the
company's operations.
II-12
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 1997 Annual Report
Southern Company is involved in various matters being litigated. See Note 3
to the financial statements for information regarding material issues that
could possibly affect future earnings.
Compliance costs related to current and future environmental laws and
regulations could affect earnings if such costs are not fully recovered. The
Clean Air Act and other important environmental items are discussed later under
"Environmental Matters."
The operating companies are subject to the provisions of FASB Statement No.
71, Accounting for the Effects of Certain Types of Regulation. In the event that
a portion of a company's operations is no longer subject to these provisions,
the company would be required to write off related regulatory assets and
liabilities that are not specifically recoverable, and determine if any other
assets have been impaired. See Note 1 to the financial statements under
"Regulatory Assets and Liabilities" for additional information.
New Accounting Standard
The FASB has issued Statement No. 130, Reporting Comprehensive Income, which
will be effective in 1998. This statement establishes standards for reporting
and display of comprehensive income and its components in a full set of general
purpose financial statements. The objective of the statement is to report a
measure of all changes in equity of an enterprise that result from transactions
and other economic events of the period other than transactions with owners
(comprehensive income). Comprehensive income is the total of net income and all
other non-owner changes in equity. Southern Company will adopt this statement in
1998.
FINANCIAL CONDITION
Overview
Southern Company's financial condition continues to remain strong. The company's
common stock closed 1997 with the highest year-end closing price in history.
Earnings, excluding the windfall profits tax, were some $1.1 billion. Based on
this performance, in January 1998, the Southern Company board of directors
increased the common stock dividend for the seventh consecutive year.
Gross property additions to utility plant were $1.9 billion in 1997. The
majority of funds needed for gross property additions since 1994 has been
provided from operating activities, principally from earnings and non-cash
charges to income. Southern Energy's business acquisitions in 1997 amounted to
approximately $2.9 billion. The Consolidated Statements of Cash Flows provide
additional details.
Derivative Financial Instruments
Southern Company is exposed to market risks in both its trading and non-trading
operations. The non-trading operations are exposed to market risks, including
changes in interest rates, currency exchange rates, and certain commodity
prices. To mitigate changes in cash flows attributable to these exposures, the
company has entered into various derivative financial instruments. Company
policy for non-trading activities stipulates that derivatives are to be used
only for hedging purposes. Derivative positions are monitored using techniques
that include market value and sensitivity analysis.
Interest rate swaps are used to hedge underlying debt obligations. These
swaps hedge specific debt issuances and therefore qualify for hedge accounting.
The company has interest rate swaps in various currencies. These match debt
issued in the same currency. In cases where debt is issued in currencies other
than the functional currency, currency swaps convert the exposure to that of the
functional currency. For qualifying hedges, the interest rate differential is
reflected as an adjustment to interest expense over the life of the instruments.
If the company sustained a 100 basis point change in interest rates for all
variable rate debt in all currencies, the change would affect annualized
interest expense by approximately $35 million at December 31, 1997. Based on the
company's overall interest rate exposure at December 31, 1997, including
derivative and other interest rate sensitive instruments, a near-term 100 basis
point change in interest rates would not materially affect the consolidated
financial statements.
The company has investments in various emerging market countries where the
net investments are not hedged, including Argentina, Chile, Trinidad, Bahamas,
Philippines, and China. The company relies on either currency pegs or
contractual or regulatory links to the U.S. dollar to mitigate currency risk
attributable to these investments. The company does not believe it has a
material exposure to changes in exchange rates between the U.S. dollar and the
currencies of these countries. The company also has investments in the United
Kingdom and Germany, and for these investments the company uses long-term
cross-currency agreements to reduce a substantial portion of its exposure to
fluctuations in the British pound sterling and German Deutschemark. These
instruments are used to hedge its net investments in these countries. As a
II-13
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 1997 Annual Report
result of these swaps, a 10 percent sustained decline of the British pound
sterling and German Deutschemark versus the U.S. dollar would not materially
affect the consolidated financial statements.
The company also uses currency swaps and forward agreements to hedge dollar
denominated debt issued by subsidiaries with different functional currency.
These swaps offset the dollar flows, thereby effectively converting debt to the
appropriate currency. Gains and losses related to qualified hedges of foreign
currency firm commitments are deferred and included in the basis of the
underlying transactions.
In addition to the non-trading activities, the company is exposed to market
risks through its electricity and natural gas commodity trading business. To
estimate and manage the market risk of its trading and marketing portfolio,
Southern Energy employs a daily Value at Risk (VAR) methodology. VAR is used to
describe a probabilistic approach to measuring the exposure to market risk. VAR
models are relatively sophisticated. However, the quantitative risk information
is limited by the parameters established in creating the model. The instruments
being evaluated may have features that may trigger a potential loss in excess of
calculated amounts if the changes in commodity prices exceed the confidence
level of the model used. The calculation utilizes the standard deviation of
seasonally adjusted historical changes in the value of the market risk sensitive
commodity-based financial instruments to estimate the amount of change (i.e.,
volatility) in the current value of these instruments that could occur at a
specified confidence level over a specified holding interval. The parameters
used in the calculation include holding intervals ranging from five to 20 days,
depending upon the type of instrument, the term of the instrument, the liquidity
of the underlying market, and other factors. The models employed a 95 percent
confidence level based on historical price movement. Based on the company's VAR
analysis of its overall commodity price risk exposure at December 31, 1997,
management does not anticipate a materially adverse effect on the company's
consolidated financial statements as a result of market fluctuations.
In the United Kingdom, the company utilizes contracts to mitigate its
exposure to volatility in the prices of electricity purchased through the
wholesale electricity market. These contracts are in place to hedge electricity
purchases on approximately 20 billion kilowatt-hours through the year 2008. The
gains or losses realized on such contracts are deferred and recognized as
electricity is purchased. Because of the absence of a trading market, it is not
practicable to estimate the fair value of these contracts.
Due to cost-based rate regulations, the operating companies have limited
exposure to market volatility in interest rates and prices of electricity. To
mitigate residual risks relative to movements in electricity prices, the
operating companies enter into fixed price contracts for the purchase and sale
of electricity through the wholesale electricity market. Realized gains and
losses are recognized in the income statement as incurred. At December 31, 1997,
exposure from these activities was not material to the consolidated financial
statements.
For additional information, see Note 1 to the financial statements under
"Financial Instruments for Non-Trading and Trading."
Capital Structure
Southern Company achieved a ratio of common equity to total capitalization --
including short-term debt -- of 38.6 percent in 1997, compared with 45.1 percent
in 1996, and 42.4 percent in 1995.
During 1997, the subsidiary companies sold, through public authorities, $404
million of pollution control revenue bonds. Preferred securities of $1.3 billion
were issued in 1997. The companies continued to reduce financing costs by
retiring higher-cost bonds and preferred stock. Retirements, including
maturities, of bonds totaled $507 million during 1997, $600 million during 1996,
and $1.3 billion during 1995. As a result, the composite interest rate on
long-term debt decreased from 7.2 percent at December 31, 1994 to 6.6 percent
at December 31, 1997. Retirements of preferred stock totaled $660 million during
1997, $179 million during 1996, and $1 million during 1995.
In 1997, Southern Company raised $360 million from the issuance of new
common stock under the company's various stock plans. At the close of 1997, the
company's common stock had a market value of 257/8 per share, compared with a
book value of $13.91 per share. The market-to-book value ratio was 186 percent
at the end of 1997, compared with 166 percent at year-end 1996, and 188 percent
at year-end 1995.
II-14
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 1997 Annual Report
Capital Requirements for Construction
The construction program of Southern Company is budgeted at $2.0 billion for
1998, $2.0 billion for 1999, and $1.6 billion for 2000. Actual construction
costs may vary from this estimate because of changes in such factors as:
business conditions; environmental regulations; nuclear plant regulations; load
projections; the cost and efficiency of construction labor, equipment, and
materials; and the cost of capital. In addition, there can be no assurance that
costs related to capital expenditures will be fully recovered.
The operating companies have approximately 1,600 megawatts of combined cycle
generation scheduled to be placed in service by 2001. Southern Energy has under
construction some 1,400 megawatts of owned capacity. Significant construction of
transmission and distribution facilities and upgrading of generating plants will
be continuing for the core business in the Southeast.
Other Capital Requirements
In addition to the funds needed for the construction program, approximately $2.5
billion will be required by the end of 2000 for present sinking fund
requirements and maturities of long-term debt. Also, the subsidiaries will
continue to retire higher-cost debt and preferred stock and replace these
obligations with lower-cost capital if market conditions permit.
Environmental Matters
In November 1990, the Clean Air Act was signed into law. Title IV of the Clean
Air Act -- the acid rain compliance provision of the law -- significantly
affected Southern Company. Specific reductions in sulfur dioxide and nitrogen
oxide emissions from fossil-fired generating plants are required in two phases.
Phase I compliance began in 1995 and initially affected 28 generating units of
Southern Company. As a result of the company's compliance strategy, an
additional 22 generating units were brought into compliance with Phase I
requirements. Phase II compliance is required in 2000, and all fossil-fired
generating plants will be affected.
Southern Company achieved Phase I sulfur dioxide compliance at the affected
plants by switching to low-sulfur coal, which required some equipment upgrades.
Construction expenditures for Phase I compliance totaled approximately $300
million.
For Phase II sulfur dioxide compliance, Southern Company could use emission
allowances, increase fuel switching, and/or install flue gas desulfurization
equipment at selected plants. Also, equipment to control nitrogen oxide
emissions will be installed on additional system fossil-fired units as necessary
to meet Phase II limits and ozone non-attainment requirements for metropolitan
Atlanta through 2000. Current compliance strategy for Phase II and ozone
non-attainment could require total estimated construction expenditures of
approximately $70 million, of which $55 million remains to be spent.
A significant portion of costs related to the acid rain provision of the
Clean Air Act is expected to be recovered through existing ratemaking
provisions. However, there can be no assurance that all Clean Air Act costs will
be recovered.
In July 1997, the Environmental Protection Agency (EPA) revised the national
ambient air quality standards for ozone and particulate matter. This revision
makes the standards significantly more stringent. Also, in October 1997, the EPA
issued a proposed regional ozone rule -- if implemented -- that could make
substantial further reductions in NOx emissions from fossil-fueled generating
facilities. Implementation of the standards and the proposed rule could result
in significant additional compliance costs and capital expenditures that cannot
be determined at this time.
The EPA and state environmental regulatory agencies are reviewing and
evaluating various other matters including: emission control strategies for
ozone non-attainment areas; additional controls for hazardous air pollutant
emissions; and hazardous waste disposal requirements. The impact of new
standards will depend on the development and implementation of applicable
regulations.
Southern Company must comply with other environmental laws and regulations
that cover the handling and disposal of hazardous waste. Under these various
laws and regulations, the subsidiaries could incur substantial costs to clean up
properties. The subsidiaries conduct studies to determine the extent of any
required cleanup costs and have recognized in their respective financial
statements costs to clean up known sites. These costs for Southern Company
amounted to $4 million in 1997 and $8 million in 1995. In 1996, the company was
reimbursed $6 million for amounts previously expensed. Additional sites may
II-15
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 1997 Annual Report
require environmental remediation for which the subsidiaries may be liable for a
portion or all required cleanup costs. See Note 3 to the financial statements
for information regarding Georgia Power's potentially responsible party status
at a site in Brunswick, Georgia.
Several major pieces of environmental legislation are being considered for
reauthorization or amendment by Congress. These include: the Clean Air Act; the
Clean Water Act; the Comprehensive Environmental Response, Compensation, and
Liability Act; the Resource Conservation and Recovery Act; the Toxic Substances
Control Act; and the Endangered Species Act. Changes to these laws could affect
many areas of Southern Company's operations. The full impact of any such changes
cannot be determined at this time.
Compliance with possible additional legislation related to global climate
change, electromagnetic fields, and other environmental and health concerns
could significantly affect Southern 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.
Sources of Capital
The amount and timing of additional equity capital to be raised in 1998 -- as
well as in subsequent years -- will be contingent on Southern Company's
investment opportunities. Equity capital can be provided from any combination of
public offerings, private placements, or the company's stock plans. Any portion
of the common stock required during 1998 for the company's stock plans that is
not provided from the issuance of new stock will be acquired on the open market
in accordance with the terms of such plans.
The operating companies plan to obtain the funds required for construction
and other purposes from sources similar to those used in the past, which were
primarily from internal sources. However, the type and timing of any financings
-- if needed -- will depend on market conditions and regulatory approval.
The operating companies historically have relied on issuances of first
mortgage bonds and preferred stock, in addition to pollution control revenue
bonds issued for their benefit by public authorities, to meet their long-term
external financing requirements. Recently, the operating companies' financings
have consisted of unsecured debt and trust preferred securities. In this regard,
the operating companies -- except Savannah Electric -- sought and obtained
stockholder approval in 1997 to amend their respective corporate charters
eliminating restrictions on the amounts of unsecured indebtedness they may
incur.
To meet short-term cash needs and contingencies, Southern Company had
approximately $601 million of cash and cash equivalents and $4.9 billion of
unused credit arrangements with banks at the beginning of 1998.
Cautionary Statement Regarding Forward-Looking
Information
Southern Company's 1997 Annual Report contains forward-looking statements in
addition to historical information. The company cautions that there are various
important factors that could cause actual results to differ materially from
those indicated in the forward-looking statements; accordingly, there can be no
assurance that such indicated results will be realized. These factors include
legislative and regulatory initiatives regarding deregulation and restructuring
of the electric utility industry; the extent and timing of the entry of
additional competition in the markets of the subsidiary companies; potential
business strategies -- including acquisitions or dispositions of assets or
internal restructuring -- that may be pursued by the company; state and federal
rate regulation in the United States; changes in or application of environmental
and other laws and regulations to which the company and its subsidiaries are
subject; political, legal and economic conditions and developments in the United
States and in foreign countries in which the subsidiaries operate; financial
market conditions and the results of financing efforts; changes in commodity
prices and interest rates; weather and other natural phenomena; the performance
of projects undertaken by the non-traditional business and the success of
efforts to invest in and develop new opportunities; and other factors discussed
in the reports -- including Form 10-K -- filed from time to time by the company
with the SEC.
II-16
II-17
II-18
II-19
II-20
II-21
II-22
NOTES TO FINANCIAL STATEMENTS
Southern Company and Subsidiary Companies 1997 Annual Report
1. SUMMARY OF SIGNIFICANT ACCOUNTING
POLICIES
General
Southern Company is the parent company of five operating companies, a system
service company, Southern Communications Services (Southern Communications),
Southern Company Energy Solutions, Southern Energy, Inc. (Southern Energy),
Southern Nuclear Operating Company (Southern Nuclear), and other direct and
indirect subsidiaries. The operating companies -- Alabama Power, Georgia Power,
Gulf Power, Mississippi Power, and Savannah Electric -- provide electric service
in four southeastern states. Contracts among the operating companies -- dealing
with jointly owned generating facilities, interconnecting transmission lines,
and the exchange of electric power -- are regulated by the Federal Energy
Regulatory Commission (FERC) and/or the Securities and Exchange Commission
(SEC). The system service company provides, at cost, specialized services to
Southern Company and subsidiary companies. Southern Communications provides
digital wireless communications services to the operating companies and also
markets these services to the public within the Southeast. Southern Company
Energy Solutions develops new business opportunities related to energy products
and services. Worldwide, Southern Energy develops and manages electricity and
other energy related projects, including domestic energy trading and marketing.
Southern Nuclear provides services to Southern Company's nuclear power plants.
Southern Company is registered as a holding company under the Public Utility
Holding Company Act of 1935 (PUHCA). Both the company and its subsidiaries are
subject to the regulatory provisions of the PUHCA. The operating companies also
are subject to regulation by the FERC and their respective state regulatory
commissions. The companies follow generally accepted accounting principles and
comply with the accounting policies and practices prescribed by their respective
commissions. The preparation of financial statements in conformity with
generally accepted accounting principles requires the use of estimates, and the
actual results may differ from those estimates. All material intercompany items
have been eliminated in consolidation.
The consolidated financial statements reflect investments in controlled
subsidiaries on a consolidated basis and other investments on an equity basis.
Effective in January 1998, Southern Energy and Vastar Resources combined their
energy trading and marketing activities to form a joint venture. Southern
Energy's investment in the joint venture will be accounted for under the equity
method of accounting. Certain prior years' data presented in the consolidated
financial statements have been reclassified to conform with the current year
presentation.
Regulatory Assets and Liabilities
The operating companies are 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
operating companies 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 expected to be credited to customers through the ratemaking process.
Regulatory assets and (liabilities) reflected in the Consolidated Balance Sheets
at December 31 relate to the following:
1997 1996
------------------------
(in millions)
Deferred income taxes $1,142 $1,238
Deferred Plant Vogtle costs 50 171
Premium on reacquired debt 285 289
Demand-side programs 11 44
Department of Energy assessments 63 69
Vacation pay 79 77
Deferred fuel charges 4 29
Postretirement benefits 38 38
Work force reduction costs 37 48
Deferred income tax credits (746) (814)
Storm damage reserves (36) (32)
Other, net 152 114
-----------------------------------------------------------------
Total $1,079 $1,271
=================================================================
In the event that a portion of an operating company's operations is no
longer subject to the provisions of FASB Statement No. 71, the company would be
required to write off related net regulatory assets and liabilities that are not
specifically recoverable through regulated rates. In addition, the company would
be required to determine if any impairment to other assets exists, including
plant, and write down the assets, if impaired, to their fair value.
II-23
NOTES (continued)
Southern Company and Subsidiary Companies 1997 Annual Report
Revenues and Fuel Costs
The operating companies accrue revenues for service rendered but unbilled at the
end of each fiscal period. Fuel costs are expensed as the fuel is used. The
operating companies' electric rates include provisions to adjust billings for
fluctuations in fuel, the energy component of purchased power costs, and certain
other costs. Revenues are adjusted for differences between recoverable fuel
costs and amounts actually recovered in current rates.
Southern Energy's revenues for product sales and marketing services are
recognized when title passes to the customer or when service is performed.
The operating companies have a diversified base of customers. No single
customer or industry comprises 10 percent or more of revenues. In 1997,
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 $144
million in 1997, $142 million in 1996, and $140 million in 1995. Alabama Power
and Georgia Power have contracts with the U.S. Department of Energy (DOE) that
provide for the permanent disposal of spent nuclear fuel. Although disposal was
scheduled to begin in 1998, the actual year this service will begin is
uncertain. Sufficient storage capacity currently is available to permit
operation into 2003 at Plant Hatch, into 2008 at Plant Vogtle, and into 2010 and
2013 at Plant Farley units 1 and 2, respectively. Activities for adding dry cask
storage capacity at Plant Hatch by as early as 1999 are in progress.
Also, the Energy Policy Act of 1992 required the establishment in 1993 of a
Uranium Enrichment Decontamination and Decommissioning Fund, which is funded in
part by a special assessment on utilities with nuclear plants. This assessment
is being paid over a 15-year period, which began in 1993. This fund will be used
by the DOE for the decontamination and decommissioning of its nuclear fuel
enrichment facilities. The law provides that utilities will recover these
payments in the same manner as any other fuel expense. Alabama Power and Georgia
Power -- based on its ownership interests -- estimate their respective remaining
liability at December 31, 1997, under this law to be approximately $34 million
and $27 million, respectively. These obligations are recorded in the
Consolidated Balance Sheets.
Depreciation and Nuclear Decommissioning
Depreciation of the original cost of depreciable utility plant in service is
provided primarily by using composite straight-line rates, which approximated
3.4 percent in 1997 and 3.3 percent in 1996 and 1995. When property subject to
depreciation is retired or otherwise disposed of in the normal course of
business, its cost -- together with the cost of removal, less salvage -- is
charged to the accumulated provision for depreciation. Minor items of property
included in the original cost of the plant are retired when the related property
unit is retired. Depreciation expense includes an amount for the expected costs
of decommissioning nuclear facilities and removal of other facilities.
Georgia Power recorded additional depreciation of electric plant amounting
to $159 million in 1997, $24 million in 1996, and $6 million in 1995. See Note 3
under "Georgia Power Retail Accounting Order" for additional information.
The Nuclear Regulatory Commission (NRC) requires all licensees operating
commercial power reactors to establish a plan for providing, with reasonable
assurance, funds for decommissioning. Alabama Power and Georgia Power have
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 periods approved by the respective state public service commissions.
The NRC's minimum external funding requirements are based on a generic estimate
of the cost to decommission the radioactive portions of a nuclear unit based on
the size and type of reactor. Alabama Power and Georgia Power have filed plans
with the NRC to ensure that -- over time -- the deposits and earnings of the
external trust funds will provide the minimum funding amounts prescribed by the
NRC.
Site study cost is the estimate to decommission a specific facility as of
the site study year, and ultimate cost is the estimate to decommission a
II-24
NOTES (continued)
Southern Company and Subsidiary Companies 1997 Annual Report
specific facility as of retirement date. The estimated costs of decommissioning
-- both site study costs and ultimate costs -- at December 31, 1997, for Alabama
Power's Plant Farley and Georgia Power's ownership interests in plants Hatch and
Vogtle were as follows:
Plant Plant Plant
Farley Hatch Vogtle
--------------------------------
Site study basis (year) 1993 1997 1997
Decommissioning periods:
Beginning year 2017 2014 2027
Completion year 2029 2027 2038
-----------------------------------------------------------------
(in millions)
Site study costs:
Radiated structures $489 $372 $317
Non-radiated structures 89 33 44
-----------------------------------------------------------------
Total $578 $405 $361
=================================================================
Ultimate costs:
Radiated structures $1,504 $722 $922
Non-radiated structures 274 65 129
-----------------------------------------------------------------
Total $1,778 $787 $1,051
=================================================================
Plant Plant Plant
Farley Hatch Vogtle
-----------------------------
(in millions)
Amount expensed in 1997 $ 18 $ 11 $ 9
Accumulated provisions:
Balance in external trust
funds $193 $118 $76
Balance in internal reserves 44 23 13
------------------------------------------------------------------
Total $237 $141 $89
==================================================================
Significant assumptions:
Inflation rate 4.5% 3.6% 3.6%
Trust earning rate 7.0 6.5 6.5
------------------------------------------------------------------
Annual provisions for nuclear decommissioning are based on an annuity method
as approved by the respective state public service commissions. All of Alabama
Power's decommissioning costs are approved for ratemaking. For Georgia Power,
only the costs to decommission the radioactive portion of the plants are
currently included in cost of service. Georgia Power's decommissioning costs
currently included in cost of service are $320 million and $267 million for
plants Hatch and Vogtle, respectively. The estimated ultimate costs associated
with the amounts currently included in cost of service are $781 million and
$1.1 billion for plants Hatch and Vogtle, respectively. Alabama Power and
Georgia Power expect their respective state public service commissions to
periodically review and adjust, if necessary, the amounts collected in rates for
the anticipated cost of decommissioning.
The decommissioning cost estimates are based on prompt dismantlement and
removal of the plant from service. The actual decommissioning costs may vary
from the above estimates because of changes in the assumed date of
decommissioning, changes in NRC requirements, or changes in the assumptions used
in making these estimates.
Income Taxes
Southern Company uses the liability method of accounting for deferred income
taxes and provides deferred income taxes for all significant income tax
temporary differences. Investment tax credits utilized are deferred and
amortized to income over the average lives of the related property.
Plant Vogtle Phase-In Plans
In 1987, 1989, and 1991, the Georgia Public Service Commission (GPSC) ordered
that the allowed costs of Plant Vogtle, a two-unit nuclear facility of which
Georgia Power owns 45.7 percent, be phased into rates. Each GPSC order called
for recovery of deferred costs within 10 years. Under these plans, all allowed
costs will be recovered by 1999.
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. The composite rates used by the operating companies to
calculate AFUDC during the years 1995 through 1997 ranged from a
before-income-tax rate of 5.8 percent to 9.8 percent. AFUDC, net of income tax,
as a percent of consolidated net income was 1.6 percent in 1997, 1.4 percent in
1996, and 1.6 percent in 1995.
Utility Plant
Utility plant is stated at original cost less regulatory disallowances. Original
cost includes: materials; labor; minor items of property; appropriate
administrative and general costs; payroll-related costs such as taxes, pensions,
and other benefits; and the estimated cost of funds used during construction.
The cost of maintenance, repairs, and replacement of minor items of property is
charged to maintenance expense. The cost of replacements of property --
exclusive of minor items of property -- is charged to utility plant.
II-25
NOTES (continued)
Southern Company and Subsidiary Companies 1997 Annual Report
Leasehold Interests
Leasehold interests include Southern Energy's power generation facilities that
are developed under build, operate, and transfer agreements with foreign
governments. Southern Energy's construction costs are initially recorded as
construction work in progress, and -- after completion -- these costs are
recorded as leasehold interests. These costs are amortized over the length of
time the facility is operated before transferring ownership to the local
government.
Cash and Cash Equivalents
For purposes of the Consolidated Statements of Cash Flows, temporary cash
investments are considered cash equivalents. Temporary cash investments are
securities with original maturities of 90 days or less.
Foreign Currency Translation
Assets and liabilities of Southern Company's international operations, where the
local currency is the functional currency, have been translated at year-end
exchange rates, and revenues and expenses have been translated using average
exchange rates prevailing during the year. Adjustments resulting from
translation have been recorded in stockholders' equity. The financial statements
of international operations, where the U.S. dollar is the functional currency
and when certain transactions are denominated in a local currency, are
remeasured in U.S. dollars. The remeasurement of local currencies into U.S.
dollars creates adjustments. These adjustments and all gains and losses from
foreign currency transactions are included in consolidated net income. Foreign
exchange gains and losses are not material for all periods presented.
Financial Instruments for Non-Trading
Non-trading derivative financial instruments are used to hedge exposures to
fluctuations in interest rates, foreign currency exchange rates, and certain
commodity prices. Gains and losses on qualifying hedges are deferred and
recognized either in income or as an adjustment to the carrying amount when the
hedged transaction occurs.
The company utilizes interest rate swaps and cross currency interest rate
swaps to minimize borrowing costs by changing the interest rate and currency of
the original borrowing. For qualifying hedges, the interest rate differential is
reflected as an adjustment to interest expense over the life of the swaps.
Southern Company's international operations are exposed to the effects of
foreign exchange rate fluctuations. To protect against this exposure, the
company utilizes currency swaps to hedge its net investment in certain foreign
subsidiaries, which has the effect of converting foreign currency cash inflows
into U.S. dollars at fixed exchange rates. Gains or losses on these currency
swaps, designated as hedges of net investment, are offset against the
translation effects reflected in stockholders' equity, net of tax.
Non-trading financial derivative instruments held at December 31, 1997, were
as follows:
Year of Unrecognized
Maturity or Notional Gain
Type Termination Amount (Loss)
------------------------------------ ---------------------------
(in millions)
Interest rate
swaps:
2002-2012 $710 $(33)
2001-2012 (pound)500 $(52)
2002-2007 DM691 $(3)
Cross currency
swaps 2001-2007 (pound)439 $6
Cross currency
swaption 2003 DM570 $1
---------------------------------------------------------------
(pound) - Denotes British pound sterling.
DM - Denotes Deutschemark.
The company is exposed to losses related to financial instruments in the
event of counterparties' nonperformance. The company has established controls to
determine and monitor the creditworthiness of counterparties in order to
mitigate the company's exposure to counterparty credit risk. The company does
not expect any of the counterparties to fail to meet their obligations.
In the United Kingdom, the company utilizes contracts to mitigate its
exposure to volatility in the prices of electricity purchased through the
wholesale electricity market. These contracts are in place to hedge electricity
purchases of approximately 20 billion kilowatt-hours through the year 2008. The
gains or losses realized on such contracts are deferred and recognized as
electricity is purchased. Because of the absence of a trading market, it is not
practicable to estimate the fair value of these contracts .
II-26
NOTES (continued)
Southern Company and Subsidiary Companies 1997 Annual Report
Other Southern Company financial instruments for which the carrying amount
did not equal fair value at December 31 were as follows:
Carrying Fair
Amount Value
--------------------------
(in millions)
Long-term debt:
At December 31, 1997 $10,916 $11,160
At December 31, 1996 7,975 8,122
Capital and preferred securities:
At December 31, 1997 1,744 1,826
At December 31, 1996 422 427
-----------------------------------------------------------------
The fair values for long-term debt and capital and preferred securities were
based on either closing market price or closing price of comparable instruments.
Financial Instruments for Trading
Derivative financial instruments used for trading purposes primarily relate to
commodities associated with the energy sector, such as electricity, natural gas,
and crude oil. These instruments are recorded at fair value for balance sheet
purposes. The determination of fair value considers various factors, such as
closing exchange prices, broker price quotations, and model pricing. Model
pricing considers time value and volatility factors underlying any options and
contractual commitments. These transactions are accounted for using the
mark-to-market method of accounting in which the unrealized gains or losses
resulting from the impact of price movements are recognized as net gains or
losses in the consolidated statements of income. If the company has a master
netting agreement with counterparties, net positions are recognized for
consolidated balance sheet and income statement purposes.
The company provides price risk management services by entering into a
variety of contractual commitments such as price cap and floor agreements,
futures contracts, forward purchase and sale agreements, and option contracts.
These contracts generally require future settlement, and are either executed on
an exchange or traded as over-the-counter (OTC) instruments. Contractual
commitments have widely varying terms and durations that range from a few hours
to a number of years depending on the instrument. The majority of the company's
transactions are short-term in duration, with a weighted average maturity of
approximately 1.3 years and 0.6 years at December 31, 1997 and 1996,
respectively.
All contractual commitments used for trading purposes are recorded at fair
value. Contracts in a net receivable position, as well as options held, are
reported as assets. Similarly, contractual commitments in a net payable
position, as well as options written, are reported as liabilities. The net
unrealized gain from risk management services amounted to $8 million at December
31, 1997. Southern Company has made guarantees to certain counterparties
regarding performance of contractual commitments by its affiliates related to
trading and marketing activities. Contractual commitments reflected in the
Consolidated Balance Sheets at December 31 were as follows:
Net Fair Value
Notional -------------------------
Amounts
1997 (Kilowatt-Hours) Assets Liabilities
---------- ---------------------------------------------
(in millions)
Exchange-issued
products:
Futures
contracts 904 $14 $15
Other 958 1 1
-------------------------------------------------------------------
Total 1,862 15 16
-------------------------------------------------------------------
OTC products:
Forward
contracts 2,643 69 62
Swaps (473) 1 -
Other 639 9 8
-------------------------------------------------------------------
Total 2,809 79 70
-------------------------------------------------------------------
Total 4,671 $94 $86
===================================================================
Net Fair Value
Notional -----------------------
Amounts
1996 (Kilowatt-Hours) Assets Liabilities
------------ ---------------------------------------------
(in millions)
Exchange-issued
products:
Futures
contracts 42 $ 3 $ 3
Other 105 - -
-------------------------------------------------------------------
Total 147 3 3
-------------------------------------------------------------------
OTC products:
Forward
contracts 56 15 15
Swaps - - -
Other 51 - -
-------------------------------------------------------------------
Total 107 15 15
-------------------------------------------------------------------
Total 254 $18 $18
===================================================================
II-27
NOTES (continued)
Southern Company and Subsidiary Companies 1997 Annual Report
Notional amounts -- stated in equivalent millions of kilowatt-hours -- are
indicative only of the volume of activity and are not a measure of market risk.
Notional amounts of natural gas and crude oil positions are reflected in
equivalent kilowatt-hours based on standard conversion rates. The company has
established controls to determine and monitor the creditworthiness of
counterparties in order to mitigate the company's exposure to counterparty
credit risk. A concentration of counterparties may impact the company's overall
exposure to credit risk, either positively or negatively, in that the
counterparties may be similarly affected by changes in economic, regulatory, or
other conditions.
The annual average gross balances of the company's options and contractual
commitments used for trading purposes, based on month-end balances were as
follows:
Average Fair Value
-------------------------
1997 Assets Liabilities
----------- -------------------------
(in millions)
Commodity instruments:
Electricity $97 $94
Gas 6 6
Other 7 6
Average Fair Value
-------------------------
1996 Assets Liabilities
----------- -------------------------
(in millions)
Commodity instruments:
Electricity $19 $18
Gas 1 1
Other - -
----------------------------------------------------------------
Materials and Supplies
Generally, materials and supplies include the costs of transmission,
distribution, and generating plant materials. Materials are charged to inventory
when purchased and then expensed or capitalized to plant, as appropriate, when
installed.
2. RETIREMENT BENEFITS
Pension Plans
The system companies have defined benefit, trusteed, pension plans that cover
substantially all regular employees. Benefits are based on one of the following
formulas: years of service and final average pay or years of service and a
flat-dollar benefit. Primarily, the companies use the "entry age normal method
with a frozen initial liability" actuarial method for funding purposes, subject
to limitations under federal income tax regulations. Amounts funded to the
pension 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
In the United States, Southern Company provides certain medical care and life
insurance benefits for retired employees. Substantially all these employees may
become eligible for such benefits when they retire. The operating companies fund
trusts to the extent deductible under federal income tax regulations or to the
extent required by their respective regulatory commissions. Amounts funded are
primarily invested in debt and equity securities.
FASB Statement No. 106, Employers' Accounting for Postretirement Benefits
Other Than Pensions, requires that medical care and life insurance benefits for
retired employees be accounted for on an accrual basis using a specified
actuarial method, "benefit/years-of-service." In October 1993, the GPSC ordered
Georgia Power to phase in the adoption of Statement No. 106 to cost of service
over a five-year period, whereby one-fifth of the additional costs was expensed
in 1993 and the remaining costs were deferred. An additional one-fifth of the
costs was expensed each succeeding year until the costs were fully reflected in
cost of service in 1997. The costs deferred during the five-year period will be
amortized to expense over a 15-year period beginning in 1998. For the other
operating companies, the cost of postretirement benefits is reflected in rates
on a current basis.
II-28
NOTES (continued)
Southern Company and Subsidiary Companies 1997 Annual Report
Funded Status and Cost of Benefits
The funded status of the plans and reconciliation to amounts reflected in the
Consolidated Balance Sheets at December 31 were as follows:
Pension
-----------------------
1997 1996
-----------------------
(in millions)
Actuarial present value of
benefit obligation:
Vested benefits $ 2,891 $ 2,730
Non-vested benefits 83 119
------------------------------------------------------------------
Accumulated benefit obligation 2,974 2,849
Additional amounts related to
projected salary increases 728 775
------------------------------------------------------------------
Projected benefit obligation 3,702 3,624
Less:
Fair value of plan assets 5,953 5,258
Unrecognized net gain (1,877) (1,314)
Unrecognized prior service cost 126 135
Unrecognized transition asset (101) (114)
------------------------------------------------------------------
Prepaid asset recognized in the
Consolidated Balance Sheets $ 399 $ 341
==================================================================
Postretirement Benefits
----------------------------
1997 1996
--------------- ------------
(in millions)
Actuarial present value of
benefit obligation:
Retirees and dependents $477 $409
Employees eligible to retire 85 78
Other employees 373 383
-------------------------------------------------------------------
Accumulated benefit obligation 935 870
Less:
Fair value of plan assets 335 260
Unrecognized net loss (gain) 68 79
Unrecognized prior service cost (4) (5)
Unrecognized transition
obligation 233 249
-------------------------------------------------------------------
Accrued liability recognized in the
Consolidated Balance Sheets $303 $287
===================================================================
The weighted average rates assumed in the actuarial calculations were:
1997 1996 1995
---------------------------------
Discount 7.5% 7.8% 7.3%
Annual salary increase 5.0 5.3 4.8
Long-term return on
plan assets 8.5 8.5 8.5
-----------------------------------------------------------------
An additional assumption used in measuring the accumulated postretirement
benefit obligation was a weighted average medical care cost trend rate of 8.8
percent for 1997, decreasing gradually to 5.5 percent through the year 2005, and
remaining at that level thereafter. An annual increase in the assumed medical
care cost trend rate of 1 percent would increase the accumulated benefit
obligation at December 31, 1997, by $80 million and the aggregate of the service
and interest cost components of the net retiree cost by $7 million.
Components of the plans' net costs are shown below:
Pension
---------------------------
1997 1996 1995
---------------------------
(in millions)
Benefits earned during the year $ 94 $ 99 $ 79
Interest cost on projected
benefit obligation 271 267 193
Actual return on plan assets (856) (564) (730)
Net amortization and deferral 417 152 412
-------------------------------------------------------------------
Net pension cost (income) $ (74) $ (46) $ (46)
===================================================================
Of the above net pension income, $52 million in 1997, $37 million in 1996,
and $30 million in 1995 were recorded in operating expenses, and the remainder
was recorded in construction and other accounts.
Postretirement Benefits
---------------------------
1997 1996 1995
---------------------------
(in millions)
Benefits earned during the year $ 18 $ 20 $ 28
Interest cost on accumulated
benefit obligation 67 60 67
Amortization of transition
obligation 15 15 27
Actual return on plan assets (28) (17) (23)
Net amortization and deferral 12 6 12
------------------------------------------------------------------
Net postretirement costs $ 84 $ 84 $111
==================================================================
Of the above net postretirement costs, $70 million in 1997, $64 million in
1996, and $78 million in 1995 were charged to operating expenses, and $3 million
in 1996 and $11 million in 1995 were deferred. The remainder for each year was
charged to construction and other accounts.
Work Force Reduction Programs
The system companies have incurred additional costs for work force reduction
programs. The costs related to these programs were $50 million, $85 million, and
$42 million for the years 1997, 1996, and 1995, respectively. In addition,
certain costs of these programs were deferred and are being amortized in
II-29
NOTES (continued)
Southern Company and Subsidiary Companies 1997 Annual Report
accordance with regulatory treatment. The unamortized balance of these costs was
$37 million at December 31, 1997.
3. LITIGATION AND REGULATORY MATTERS
Alabama Power Appliance Warranty Litigation
In 1996, legal actions against Alabama Power were filed in several counties in
Alabama charging Alabama Power with fraud and non-compliance with regulatory
statutes relating to the offer, sale, and financing of "extended service
contracts" in connection with the sale of electric appliances. Some of these
suits were filed as class actions, while others were filed on behalf of multiple
individual plaintiffs. The plaintiffs seek damages for an unspecified amount.
Alabama Power has offered extended service agreements to its customers since
January 1984, and approximately 175,000 extended service agreements could be
involved in these proceedings. The final outcome of these cases cannot now be
determined.
Georgia Power Potentially Responsible Party Status
In January 1995, Georgia Power and four other unrelated entities were notified
by the Environmental Protection Agency (EPA) that they have been designated as
potentially responsible parties under the Comprehensive Environmental Response,
Compensation, and Liability Act with respect to a site in Brunswick, Georgia. As
of December 31, 1997, Georgia Power had recorded approximately $5 million in
expenses associated with the site. This represents Georgia Power's agreed upon
share of removal and remedial investigation and feasibility study costs.
The final outcome of this matter cannot now be determined. However, based on
the nature and extent of Georgia Power's activities relating to the site,
management believes that the company's portion of any remaining remediation
costs should not be material to the financial statements.
Georgia Power Investment in Rocky Mountain
In its 1985 financing order, the GPSC concluded that completion of the Rocky
Mountain pumped storage hydroelectric plant in 1991 as then planned was not
economically justifiable and reasonable and withheld authorization for Georgia
Power to spend funds from approved securities issuances on that plant. In 1988,
Georgia Power and Oglethorpe Power Corporation (OPC) entered into a joint
ownership agreement for OPC to assume responsibility for the construction and
operation of the plant. The plant went into commercial operation in 1995.
In June 1996, the GPSC initiated a review of this plant. On January 14,
1998, the GPSC ordered that Georgia Power be allowed to include approximately
$108 million of its $143 million investment in rate base as of December 31,
1998. Georgia Power has appealed the GPSC's order to the Superior Court of
Fulton County, Georgia. If the order is upheld, Georgia Power will be required
to record a write-off currently estimated to be approximately $29 million, after
taxes.
The final outcome of this matter cannot now be determined. Accordingly, no
provision related to the GPSC's disallowance has been recorded.
FERC Reviews Equity Returns
In May 1991, the FERC ordered that hearings be conducted concerning the
reasonableness of the operating companies' wholesale rate schedules and
contracts that have a return on common equity of 13.75 percent or greater. The
contracts that could be affected by the hearings include substantially all of
the transmission, unit power, long-term power, and other similar contracts.
In August 1992, a FERC administrative law judge issued an opinion that
changes in rate schedules and contracts were not necessary and that the FERC
staff failed to show how any changes were in the public interest. The FERC staff
has filed exceptions to the administrative law judge's opinion, and the matter
remains pending before the FERC.
In August 1994, the FERC instituted another proceeding based on
substantially the same issues as in the 1991 proceeding. In November 1995, a
FERC administrative law judge issued an opinion that the FERC staff failed to
meet its burden of proof, and therefore, no change in the equity return was
necessary. The FERC staff has filed exceptions to the administrative law judge's
opinion, and the matter is pending before the FERC.
If the rates of return on common equity recommended by the FERC staff were
applied to all of the schedules and contracts involved in both proceedings -- as
well as to certain other contracts that reference these proceedings in
determining return on common equity -- and if refunds were ordered, the amount
II-30
NOTES (continued)
Southern Company and Subsidiary Companies 1997 Annual Report
of refunds could range up to approximately $194 million at December 31, 1997.
Although management believes that rates are not excessive and that refunds are
not justified, the final outcome of this matter cannot now be determined.
Southern Company Tax Litigation
In August 1997, Southern Company and the Internal Revenue Service (IRS) entered
into a settlement agreement related to tax issues for the years 1984 through
1987. The agreement is subject to the review and approval by the Joint
Congressional Committee on Taxation. If approved by the Joint Committee, the
agreement would resolve all issues in the case for the years before the U.S. Tax
Court, resulting in a refund to Southern Company of approximately $162 million.
This amount includes interest of $76 million. The tax litigation was related to
a timing issue as to when taxes should have been paid; therefore, only the
interest portion will affect future income. There can be no assurance that such
Joint Committee approval will be received.
Alabama Power Rate Adjustment Procedures
In November 1982, the Alabama Public Service Commission (APSC) adopted rates
that provide for periodic adjustments based upon Alabama Power's earned return
on end-of-period retail common equity. The rates also provide for adjustments to
recognize the placing of new generating facilities in retail service. Both
increases and decreases have been placed into effect since the adoption of these
rates. The rate adjustment procedures allow a return on common equity range of
13.0 percent to 14.5 percent and limit increases or decreases in rates to 4
percent in any calendar year.
In June 1995, the APSC issued a rate order granting Alabama Power's request
for gradual adjustments to move toward parity among customer classes. This order
also calls for a moratorium on any periodic retail rate increases (but not
decreases) until July 2001.
In December 1995, the APSC issued an order authorizing Alabama Power to
reduce balance sheet items -- such as plant and deferred charges -- at any time
the company's actual base rate revenues exceed the budgeted revenues. In April
1997, the APSC issued an additional order authorizing Alabama Power to reduce
balance sheet asset items. This order authorizes the reduction of such items up
to an amount equal to five times the total estimated annual revenue reduction
resulting from future rate reductions initiated by Alabama Power.
The ratemaking procedures will remain in effect until the APSC votes to
modify or discontinue them.
Georgia Power Retail Accounting Order
In February 1996, the GPSC approved a three-year accounting order, effective
January 1, 1996. Under the accounting order, Georgia Power's earnings are
evaluated against a retail return on common equity range of 10 percent to 12.5
percent. Earnings in excess of 12.5 percent will be used to accelerate the
amortization of regulatory assets or to accelerate the depreciation of electric
plant. At its option, Georgia Power may also accelerate amortization or
depreciation of assets while within the range allowed on common equity. Georgia
Power is required to absorb cost increases of approximately $29 million annually
during the three-year period, including $14 million annually of accelerated
depreciation of electric plant. Under the accounting order, Georgia Power will
not file for a general base rate increase unless its projected retail return on
common equity falls below 10 percent. On July 1, 1998, Georgia Power is required
to file a general rate case. In response, the GPSC would be expected to either
continue the provisions of the accounting order or adopt new ones.
A consumer group appealed the GPSC's decision to the Superior Court of
Fulton County, Georgia. In 1996, the superior court ruled that statutory
requirements applicable to rate cases were not followed and remanded the matter
to the GPSC. In October 1997, the Georgia Court of Appeals upheld the accounting
order and reversed the superior court's decision. This matter is now concluded.
4. CONSTRUCTION PROGRAM
The system companies are engaged in continuous construction programs, currently
estimated to total some $2.0 billion in 1998, $2.0 billion in 1999, and $1.6
billion in 2000. The construction programs are subject to periodic review and
revision, and actual construction costs may vary from the above estimates
because of numerous factors. These factors include: changes in business
conditions; revised load growth estimates; changes in environmental regulations;
changes in existing nuclear plants to meet new regulatory requirements;
increasing costs of labor, equipment, and materials; and cost of capital. At
December 31, 1997, significant purchase commitments were outstanding in
connection with the construction program. The operating companies have
approximately 1,600 megawatts of combined cycle generation scheduled to be
placed in service by 2001. Southern Energy has under construction some 1,400
II-31
NOTES (continued)
Southern Company and Subsidiary Companies 1997 Annual Report
megawatts of owned capacity. In addition, significant construction will continue
related to transmission and distribution facilities and the upgrading of
generating plants.
See Management's Discussion and Analysis under "Environmental Matters" for
information on the impact of the Clean Air Act Amendments of 1990 and other
environmental matters.
5. FINANCING, INVESTMENTS, AND
COMMITMENTS
General
The amount and timing of additional equity capital to be raised in 1998 -- as
well as in subsequent years -- will be contingent on Southern Company's
investment opportunities. Equity capital can be provided from any combination of
public offerings, private placements, or the company's stock plans.
The operating companies' construction programs are expected to be financed
primarily from internal sources. Short-term debt is often utilized and the
amounts available are discussed below. The companies may issue additional
long-term debt and preferred securities primarily for debt maturities and for
redeeming higher-cost securities if market conditions permit.
Bank Credit Arrangements
At the beginning of 1998, unused credit arrangements with banks totaled $4.9
billion, of which $3.0 billion expires during 1998, $800 million during 1999 to
2001, and $1.0 billion during 2002. The following table outlines the credit
arrangements by company:
Amount of Credit
-----------------------------------------
Expires
--------------------
1999 &
Company Total Unused 1998 beyond
------------- -----------------------------------------
(in millions)
Alabama Power $ 814 $ 814 $ 679 $ 135
Georgia Power 1,144 1,144 919 225
Gulf Power 103 94 94 -
Mississippi Power 96 76 56 20
Savannah Electric 41 41 21 20
Southern Company 2,000 2,000 1,000 1,000
Southern Energy 1,038 635 193 442
Other 70 66 66 -
------------------------------------------
Total $5,306 $4,870 $3,028 $1,842
==========================================
Approximately $2.1 billion of the credit facilities allows for term loans
ranging from one to three years. Most of the agreements include stated
borrowing rates but also allow for competitive bid loans.
All of the credit arrangements require payment of commitment fees based on
the unused portion of the commitments or the maintenance of compensating
balances with the banks. These balances are not legally restricted from
withdrawal. Of Southern Company's credit facilities, $1.7 billion is a
syndicated credit arrangement which also requires the payment of agent fees.
A portion of the $4.9 billion unused credit with banks is allocated to
provide liquidity support to the companies' variable rate pollution control
bonds. At December 31, 1997, the amount of the credit lines allocated for this
purpose was $1.2 billion.
In addition, the companies from time to time borrow under uncommitted lines
of credit with banks, and in the case of Southern Company, Alabama Power,
Georgia Power, and Southern Energy, through commercial paper programs that have
the liquidity support of committed bank credit arrangements.
Assets Subject to Lien
Each of Southern Company's subsidiaries is organized as a legal entity,
separate, and apart from Southern Company and its other subsidiaries. The
subsidiary companies' mortgages, which secure the first mortgage bonds issued by
the companies, constitute a direct first lien on substantially all of the
companies' respective fixed property and franchises. There are no agreements or
other arrangements among the subsidiary companies under which the assets of one
company have been pledged or otherwise made available to satisfy obligations of
Southern Company or any of its subsidiaries.
Fuel and Purchased Power Commitments
To supply a portion of the fuel requirements of the generating plants, Southern
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.
II-32
NOTES (continued)
Southern Company and Subsidiary Companies 1997 Annual Report
Also, Southern Company has entered into various long-term commitments for the
purchase of electricity. Total estimated long-term obligations at December 31,
1997, were as follows:
Purchased
Year Fuel Power
----------- ------------------------------
(in millions)
1998 $ 2,081 $ 338
1999 1,596 164
2000 1,235 175
2001 1,122 178
2002 1,005 182
2003 and thereafter 4,580 1,720
-------------------------------------------------------------
Total commitments $11,619 $2,757
=============================================================
Operating Leases
Southern Company has operating lease agreements with various terms and
expiration dates. These expenses totaled $33 million, $23 million, and $17
million for 1997, 1996, and 1995, respectively. At December 31, 1997, estimated
minimum rental commitments for noncancelable operating leases were as follows:
Year Amounts
-------- -----------------
(in millions)
1998 $ 39
1999 37
2000 32
2001 28
2002 28
2003 and thereafter 291
-------------------------------------------------------------
Total minimum payments $455
=============================================================
6. FACILITY SALES AND JOINT OWNERSHIP
AGREEMENTS
In 1992, Alabama Power sold an undivided interest in units 1 and 2 of Plant
Miller and related facilities to Alabama Electric Cooperative, Inc.
Since 1975, Georgia Power has sold undivided interests in plants Vogtle,
Hatch, Scherer, and Wansley in varying amounts, together with transmission
facilities, to OPC, the Municipal Electric Authority of Georgia, and the city of
Dalton, Georgia. In addition, Georgia Power has joint ownership agreements with
OPC for the Rocky Mountain project and with Florida Power Corporation (FPC) for
a combustion turbine unit at Intercession City, Florida.
At December 31, 1997, Alabama Power's and Georgia Power's ownership and
investment (exclusive of nuclear fuel) in jointly owned facilities with the
above entities were as follows:
Jointly Owned Facilities
-------------------------------------------------
Percent Amount of Accumulated
Ownership Investment Depreciation
------------------- ------------------------------
Plant Vogtle (in millions)
(nuclear) 45.7% $3,299 $1,100
Plant Hatch
(nuclear) 50.1 840 477
Plant Miller
(coal)
Units 1 and 2 91.8 717 311
Plant Scherer
(coal)
Units 1 and 2 8.4 112 44
Plant Wansley
(coal) 53.5 298 136
Rocky Mountain
(pumped storage) 25.4 202 44
Intercession City
(combustion turbine) 33.3 13 *
------------------------------------------------------------------
*Less than $1 million.
Alabama Power and Georgia Power have contracted to operate and maintain the
jointly owned facilities -- except for the Rocky Mountain project and
Intercession City -- as agents for their respective co-owners. The companies'
proportionate share of their plant operating expenses is included in the
corresponding operating expenses in the Consolidated Statements of Income.
7. LONG-TERM POWER SALES
AGREEMENTS
The operating companies have long-term contractual agreements for the sale of
capacity and energy to certain non-affiliated utilities located outside the
system's service area. These agreements -- expiring at various dates discussed
below -- are firm and pertain to capacity related to specific generating units.
Because the energy is generally sold at cost under these agreements,
profitability is primarily affected by revenues from capacity sales. The
capacity revenues amounted to $203 million in 1997, $217 million in 1996, and
$237 million in 1995.
Unit power from specific generating plants is currently being sold to
Florida Power & Light Company (FP&L), FPC, Jacksonville Electric Authority
(JEA), and the city of Tallahassee, Florida. Under these agreements,
approximately 1,600 megawatts of capacity is scheduled to be sold annually
through 1999. Thereafter, these sales will decline to some 1,500 megawatts and
II-33
NOTES (continued)
Southern Company and Subsidiary Companies 1997 Annual Report
remain at that approximate level -- unless reduced by FP&L, FPC, and JEA for the
periods after 1999 with a minimum of three years notice -- until the expiration
of the contracts in 2010.
8. INCOME TAXES
At December 31, 1997, the tax-related regulatory assets and liabilities were
$1.1 billion and $746 million, respectively. These assets are attributable to
tax benefits flowed through to customers in prior years and to taxes applicable
to capitalized AFUDC. These liabilities are attributable to deferred taxes
previously recognized at rates higher than current enacted tax law and to
unamortized investment tax credits.
Details of income tax provisions are as follows:
1997 1996 1995
-----------------------------
(in millions)
Total provision for income taxes:
Federal --
Currently payable $ 547 $569 $ 567
Deferred -- current year 188 116 185
-- reversal of
prior years (160) (74) (111)
--------------------------------------------------------------------
575 611 641
--------------------------------------------------------------------
State --
Currently payable 104 82 90
Deferred -- current year 15 23 26
-- reversal of
prior years (19) (9) (12)
--------------------------------------------------------------------
100 96 104
--------------------------------------------------------------------
International -
Windfall profits tax
assessed in United Kingdom 148 - -
Other 16 50 24
--------------------------------------------------------------------
Total 839 757 769
Less income taxes charged
(credited) to other income 114 10 (36)
--------------------------------------------------------------------
Total income taxes charged
to operations $ 725 $747 $ 805
====================================================================
The first half of the windfall profits tax assessed in the United Kingdom
was paid in December 1997, and the remainder is due December 1998.
The tax effects of temporary differences between the carrying amounts of
assets and liabilities in the financial statements and their respective tax
bases, which give rise to deferred tax assets and liabilities, are as follows:
1997 1996
---------------------
(in millions)
Deferred tax liabilities:
Accelerated depreciation $3,345 $2,981
Property basis differences 1,756 2,154
Other 269 362
-----------------------------------------------------------------
Total 5,370 5,497
-----------------------------------------------------------------
Deferred tax assets:
Federal effect of state deferred taxes 108 110
Other property basis differences 245 253
Deferred costs 116 139
Pension and other benefits 72 68
Other 197 214
-----------------------------------------------------------------
Total 738 784
-----------------------------------------------------------------
Net deferred tax liabilities 4,632 4,713
Portion included in current assets, net 18 25
-----------------------------------------------------------------
Accumulated deferred income taxes
in the Consolidated Balance Sheets $4,650 $4,738
=================================================================
Deferred investment tax credits are amortized over the life of the related
property with such amortization normally applied as a credit to reduce
depreciation in the Consolidated Statements of Income. Credits amortized in this
manner amounted to $30 million in 1997, $33 million in 1996, and $38 million in
1995. At December 31, 1997, all investment tax credits available to reduce
federal income taxes payable had been utilized.
A reconciliation of the federal statutory income tax rate to the effective
income tax rate is as follows:
1997 1996 1995
-------------------------------
Federal statutory rate 35.0% 35.0% 35.0%
State income tax,
net of federal deduction 3.4 3.2 3.4
Non-deductible book
depreciation 2.3 1.8 1.6
Windfall profits tax 8.0 - -
Difference in prior years'
deferred and current tax rate (1.5) (1.0) (1.1)
Other (1.9) (0.5) 0.3
----------------------------------------------------------------------
Effective income tax rate 45.3% 38.5% 39.2%
======================================================================
Southern Company files a consolidated federal income tax return. Under a
joint consolidated income tax agreement, each subsidiary's current and deferred
tax expense is computed on a stand-alone basis. Tax benefits from losses of the
parent company are allocated to each subsidiary based on the ratio of taxable
income to total consolidated taxable income.
II-34
NOTES (continued)
Southern Company and Subsidiary Companies 1997 Annual Report
9. COMMON STOCK
Shares Reserved
At December 31, 1997, a total of 49 million shares was reserved for issuance
pursuant to the Southern Investment Plan, the Employee Savings Plan, the Outside
Directors Stock Plan, and the Performance Stock Plan.
Performance Stock Plan
Southern Company's Executive Stock Option Plan was replaced by the Performance
Stock Plan effective February 17, 1997. As of December 31, 1997, 283 current and
former employees participated in the plan. The maximum number of shares of
common stock that may be issued under the new plan may not exceed 40 million.
The prices of options granted to date have been at the fair market value of the
shares on the dates of grant. The first grant under the new plan was in July
1997. Options granted to date become exercisable pro rata over a maximum period
of four years from the date of grant. Options outstanding will expire no later
than 10 years after the date of grant, unless terminated earlier by the Southern
Company Board of Directors in accordance with the plan. Stock option activity
in 1996 and 1997 for both plans are summarized below:
Shares Average
Subject Option Price
To Option Per Share
----------------------------------
Balance at December 31, 1995 2,476,299 $19.87
Options granted 1,460,731 23.00
Options canceled (13,878) 22.35
Options exercised (97,988) 17.94
--------------------------------------------------------------------
Balance at December 31, 1996 3,825,164 21.11
Options granted 1,776,094 21.25
Options canceled (51,913) 21.83
Options exercised (137,426) 19.72
--------------------------------------------------------------------
Balance at December 31, 1997 5,411,919 $21.18
====================================================================
Shares reserved for future grants:
At December 31, 1995 2,114,915
At December 31, 1996 668,062
At December 31, 1997 38,234,044
--------------------------------------------------------------------
Options exercisable:
At December 31, 1996 1,279,830
At December 31, 1997 1,996,724
--------------------------------------------------------------------
Southern Company accounts for its stock-based compensation plans in
accordance with Accounting Principles Board Opinion No. 25. Accordingly, no
compensation expense has been recognized.
The pro forma impact on earnings of fair-value accounting for options
granted -- as required by FASB Statement No. 123, Accounting for Stock-Based
Compensation -- is less than 1 cent per share and is not significant to the
consolidated financial statements.
Earnings Per Share
In 1997, Southern Company adopted FASB Statement No. 128, Earnings per Share.
This statement simplifies the methodology for computing both basic and diluted
earnings per share. The only difference in the two methods for computing
Southern Company's per share amounts is attributable to outstanding options,
under the Performance Stock Plan. The effect of the stock options was determined
using the treasury stock method. Consolidated net income as reported was not
affected. Shares used to compute diluted earnings per share are as follows:
Average Common Stock Shares
--------------------------------------
1997 1996 1995
--------------------------------------
(in thousands)
As reported shares 685,033 672,590 665,064
Effect of options 191 200 170
--------------------------------------
Diluted shares 685,224 672,790 665,234
======================================
Common Stock Dividend Restrictions
The income of Southern Company is derived primarily from equity in earnings of
its subsidiaries. At December 31, 1997, consolidated retained earnings included
$3.8 billion of undistributed retained earnings of the subsidiaries. Of this
amount, $2.0 billion was restricted against the payment by the subsidiary
companies of cash dividends on common stock under terms of bond indentures.
10. CAPITAL AND PREFERRED SECURITIES
Company or subsidiary obligated mandatorily redeemable capital and preferred
securities have been issued by special purpose financing entities of Southern
Company and its subsidiaries. Substantially all the assets of these special
financing entities are junior subordinated notes issued by the related company
seeking financing. Each of these companies considers that the mechanisms and
obligations relating to the capital or preferred securities issued for its
II-35
NOTES (continued)
Southern Company and Subsidiary Companies 1997 Annual Report
benefit, taken together, constitute a full and unconditional guarantee by it of
the respective special financing entities' payment obligations with respect to
the capital or preferred securities. At December 31, 1997, preferred securities
of $1.1 billion and capital securities of $600 million were outstanding.
Southern Company guarantees the notes related to $600 million of capital
securities issued on its behalf.
11. OTHER LONG-TERM DEBT
Details of other long-term debt at December 31 are as follows:
1997 1996
--------------------
(in millions)
Obligations incurred in connection
with the sale by public authorities
of pollution control
revenue bonds:
Collateralized --
4.375% to 9.375% due
2000-2026 $1,154 $1,403
Variable rates (3.85% to 5.20%
at 1/1/98) due 2011-2025 639 639
Non-collateralized --
7.25% due 2003 1 1
6.75% to 8.375% due 2015-2020 109 200
5.8% due 2022 10 10
Variable rates (4.50% to 5.90%
at 1/1/98) due 2021-2037 670 265
----------------------------------------------------------------
2,583 2,518
----------------------------------------------------------------
Capitalized lease obligations 142 151
----------------------------------------------------------------
Long-term notes payable:
4% to 11% due 1997-2000 295 301
5.502% to 10.56% due 2001-2037 1,741 793
7.125% due 2047 194 -
Adjustable rates (5.70% to 13% at
1/1/98) due 1997-2000 703 240
Adjustable rates (3.77% to
8.0781% at 1/1/98) due
2001-2007 1,533 81
----------------------------------------------------------------
4,466 1,415
----------------------------------------------------------------
Total $7,191 $4,084
================================================================
With respect to the collateralized pollution control revenue bonds, the
operating companies have authenticated and delivered to trustees a like
principal amount of first mortgage bonds as security for obligations under
installment sale or loan agreements. The principal and interest on the first
mortgage bonds will be payable only in the event of default under the
agreements.
Sinking fund requirements and/or serial maturities through 2002 applicable to
other long-term debt are as follows: $400 million in 1998; $610 million in 1999;
$364 million in 2000; $323 million in 2001; and $939 million in 2002.
12. LONG-TERM DEBT DUE WITHIN ONE YEAR
A summary of the improvement fund requirements and scheduled maturities and
redemptions of long-term debt due within one year at December 31 is as follows:
1997 1996
----------------
(in millions)
Bond improvement fund requirements $ 38 $ 40
Less:
Portion to be satisfied by certifying
property additions 3 4
-----------------------------------------------------------------
Cash sinking fund requirements 35 36
First mortgage bond maturities
and redemptions 349 76
Other long-term debt maturities
(Note 11) 400 79
-----------------------------------------------------------------
Total $784 $191
=================================================================
The first mortgage bond improvement (sinking) fund requirements amount to 1
percent of each outstanding series of bonds authenticated under the indentures
prior to January 1 of each year, other than those issued to collateralize
pollution control and other obligations. The requirements may be satisfied by
depositing cash or reacquiring bonds, or by pledging additional property equal
to 166 2/3 percent of such requirements.
13. NUCLEAR INSURANCE
Under the Price-Anderson Amendments Act of 1988, Alabama Power and Georgia Power
maintain agreements of indemnity with the NRC that, together with private
insurance, cover third-party liability arising from any nuclear incident
occurring at the companies' nuclear power plants. The act 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
II-36
NOTES (continued)
Southern Company and Subsidiary Companies 1997 Annual Report
than an aggregate of $10 million per incident to be paid in a calendar year for
each reactor. Such maximum assessment, excluding any applicable state premium
taxes, for Alabama Power and Georgia Power -- based on its ownership and buyback
interests -- is $159 million and $160 million, respectively, per incident, but
not more than an aggregate of $20 million per company to be paid for each
incident in any one year.
Alabama Power and Georgia Power are members of Nuclear Electric Insurance
Limited (NEIL), 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. Alabama Power's and Georgia
Power's maximum annual assessments are limited to $8 million and $10 million,
respectively, under current primary policies.
Additionally, both companies have policies that currently provide
decontamination, excess property insurance, and premature decommissioning
coverage up to $2.25 billion for losses in excess of the $500 million primary
coverage. This excess insurance is also provided by NEIL.
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 17 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 current policies for Alabama
Power and Georgia Power for excess property damage would be $10 million and $11
million, respectively. The maximum replacement power assessments are $8 million
for Alabama Power and $11 million for Georgia Power.
For all on-site property damage insurance policies for commercial nuclear
power plants, the NRC requires that the proceeds of such policies issued or
renewed on or after April 2, 1991, shall be dedicated first for the sole purpose
of placing the reactor in a safe and stable condition after an accident. Any
remaining proceeds are to be applied next toward the costs of decontamination
and debris removal operations ordered by the NRC, and any further remaining
proceeds are to be paid either to the company or to its bond trustees as may be
appropriate under the policies and applicable trust indentures.
All retrospective assessments -- whether generated for liability, property,
or replacement power -- may be subject to applicable state premium taxes.
14. ACQUISITIONS
In 1997, Southern Energy acquired a 26 percent interest in an integrated utility
in Berlin, Germany for approximately $820 million. Southern Energy also
completed in 1997 the acquisition of a 100 percent interest in Consolidated
Electric Power Asia (CEPA) for a total net investment of some $2.1 billion. CEPA
is the largest independent power producer in Asia. The acquisition has been
accounted for under the purchase method of accounting. The acquisition cost
exceeded the fair market value of net assets by approximately $1.6 billion. This
amount is considered goodwill and is being amortized on a straight-line basis
over 40 years.
CEPA has been included in the consolidated financial statements since
January 29, 1997. The following unaudited pro forma results of operations for
the years 1997 and 1996 have been prepared assuming the acquisition of CEPA,
effective January 1, 1996. The pro forma results assume acquisition financing of
$716 million of short-term borrowings, $792 million of long-term notes, and $600
million of capital securities. Southern Company's assumed effective composite
interest rate on these obligations for each period was 6.82 percent.
In 1995, Southern Energy acquired SWEB for approximately $1.8 billion. The
British utility distributes electricity to some 1.3 million customers. The
acquisition has been accounted for under the purchase method of accounting.
Goodwill of $287 million is being amortized over 40 years. SWEB has been
included in the consolidated financial statements since September 1995. The
following pro forma results of operations for the year 1995 has been prepared
assuming the acquisition of SWEB, effective January 1, 1994, and assuming 100
percent short-term debt financing.
These unaudited pro forma results are not necessarily indicative of the
actual results that would have been realized had the acquisitions occurred on
the assumed dates, nor are they necessarily indicative of future results. Pro
forma operating results are for information purposes only and are as follows:
II-37
Business Segments
II-38
NOTES (continued)
Southern Company and Subsidiary Companies 1997 Annual Report
Products and Services
II-39
II-40
II-42B
II-42C
II-43
II-44A
II-44B
II-44C
II-45
II-46A
II-46B
II-46C
II-47
II-48A
II-48B
II-48C
II-49
II-50A
II-50B
II-50C
II-51
II-52A
II-52B
II-52C
II-53
II-54A
II-54B
ALABAMA POWER COMPANY
FINANCIAL SECTION
II-55
MANAGEMENT'S REPORT
Alabama Power Company 1997 Annual Report
The management of Alabama Power Company has prepared -- and is responsible for
-- the financial statements and related information included in this report.
These statements were prepared in accordance with generally accepted accounting
principles appropriate in the circumstances and necessarily include amounts that
are based on the best estimates and judgments of management. Financial
information throughout this annual report is consistent with the financial
statements.
The company maintains a system of internal accounting controls to provide
reasonable assurance that assets are safeguarded and that the books and records
reflect only authorized transactions of the company. Limitations exist in any
system of internal controls, however, based on a recognition that the cost of
the system should not exceed its benefits. The company believes its system of
internal accounting controls maintains an appropriate cost/benefit relationship.
The company's system of internal accounting controls is evaluated on an
ongoing basis by the company's internal audit staff. The company's independent
public accountants also consider certain elements of the internal control system
in order to determine their auditing procedures for the purpose of expressing an
opinion on the financial statements.
The audit committee of the board of directors, composed of directors who are
not employees, provides a broad overview of management's financial reporting and
control functions. Periodically, this committee meets with management, the
internal auditors and the independent public accountants to ensure that these
groups are fulfilling their obligations and to discuss auditing, internal
controls, and financial reporting matters. The internal auditors and independent
public accountants have access to the members of the audit committee at any
time.
Management believes that its policies and procedures provide reasonable
assurance that the company's operations are conducted according to a high
standard of business ethics.
In management's opinion, the financial statements present fairly, in all
material respects, the financial position, results of operations and cash flows
of Alabama Power Company in conformity with generally accepted accounting
principles.
/s/Elmer B. Harris
Elmer B. Harris
President and Chief Executive Officer
/s/William B. Hutchins, III
William B. Hutchins, III
Executive Vice President, Chief Financial Officer,
and Treasurer
February 11, 1998
II-56
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors
of Alabama Power Company:
We have audited the accompanying balance sheets and statements of capitalization
of Alabama Power Company (an Alabama corporation and a wholly owned subsidiary
of Southern Company) as of December 31, 1997 and 1996, and the related
statements of income, retained earnings, and cash flows for each of the three
years in the period ended December 31, 1997. 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 11-65 through II-82)
referred to above present fairly, in all material respects, the financial
position of Alabama Power Company as of December 31, 1997 and 1996, and the
results of its operations and its cash flows for each of the three years in the
period ended December 31, 1997, in conformity with generally accepted accounting
principles.
/s/Arthur Andersen LLP
Birmingham, Alabama
February 11, 1998
II-57
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL
CONDITION
Alabama Power Company 1997 Annual Report
RESULTS OF OPERATIONS
Earnings
Alabama Power Company's 1997 net income after dividends on preferred stock was
$376 million, representing a $4.4 million (1.2 percent) increase from the prior
year. This improvement can be attributed primarily to lower non-fuel related
operating expenses. Despite the mild weather experienced during 1997, retail
sales increased approximately 2 percent. However, the expected net income effect
was offset by reductions in certain industrial and commercial prices.
In 1996, earnings were $371 million, representing a 2.9 percent increase
from the prior year. This increase was due to an increase in retail energy
sales of 2.7 percent from 1995 levels and lower net interest charges compared
to the prior year. This improvement was partially offset by a 4.4 percent
increase in operating costs.
The return on average common equity for 1997 was 13.76 percent compared to
13.75 percent in 1996, and 13.61 percent in 1995.
Revenues
Operating revenues for 1997 were $3.1 billion, reflecting a 0.9 percent increase
from 1996. The following table summarizes the principal factors that affected
operating revenues for the past three years:
Increase (Decrease)
From Prior Year
--------------------------------------
1997 1996 1995
--------------------------------------
(in thousands)
Retail --
Growth and price
change $ 33,813 $ 42,385 $ 19,164
Weather (22,973) (29,660) 54,888
Fuel cost recovery
and other 31,353 (30,846) 35,235
-------------------------------------------------------------
Total retail 42,193 (18,121) 109,287
-------------------------------------------------------------
Sales for resale --
Non-affiliates 39,354 21,529 15,380
Affiliates (54,825) 88,890 (37,032)
-------------------------------------------------------------
Total sales for resale (15,471) 110,419 (21,652)
Other operating
revenues 1,614 3,703 1,997
-------------------------------------------------------------
Total operating
revenues $ 28,336 $ 96,001 $ 89,632
-------------------------------------------------------------
Percent change 0.9% 3.2% 3.1%
=============================================================
Retail revenues of $2.5 billion in 1997 increased $42 million (1.7 percent)
from the prior year, compared with a decrease of $18 million (0.7 percent) in
1996. Fuel revenues increased in 1997 due to slightly higher generation and
higher fuel costs. This was the primary reason for the increase in 1997 retail
revenues over 1996. Lower fuel cost recovery was the primary reason for the
decrease in 1996 retail revenues as compared to 1995. Fuel revenues generally
represent the direct recovery of fuel expense, including the fuel component of
purchased energy, and therefore have no effect on net income.
Revenues from sales to utilities outside the service area under
long-term contracts consist of capacity and energy components. Capacity revenues
reflect the recovery of fixed costs and a return on investment under the
contracts. Energy is generally sold at variable cost. These capacity
II-58
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 1997 Annual Report
and energy components were:
1997 1996 1995
-------------------------------------------
(in thousands)
Capacity $136,248 $150,797 $157,119
Energy 134,498 107,996 83,352
----------------------------------------------------------
Total $270,746 $258,793 $240,471
==========================================================
Capacity revenues from non-affiliates in 1997 decreased 9.6% compared to
1996 primarily due to a one-time unit power sales adjustment in 1997. Capacity
revenues from non-affiliates were relatively constant in 1996 and 1995.
Kilowatt-hour (KWH) sales for 1997 and the percent change by year were as
follows:
KWH Percent Change
----------- -------------------------------
1997 1997 1996 1995
-------------------------------- ----------
(millions)
Residential 14,336 (1.8)% 1.5% 9.1%
Commercial* 11,330 3.9 8.6 4.1
Industrial* 20,728 3.6 0.7 2.0
Other 181 (6.3) 3.1 0.5
----------
Total retail 46,575 1.9 2.7 4.7
Sales for resale -
Non-affiliates 11,894 25.3 18.0 18.8
Affiliates 8,993 (12.6) 53.5 (20.5)
----------
Total 67,462 3.0% 10.5% 2.6%
-----------------------------------------------------------------
*The KWH sales for 1996 reflect a reclassification of approximately 200
customers from industrial to commercial, which resulted in a shift of 473
million KWH. Absent the reclassification, the percentage change in KWH sales for
commercial and industrial would have been 3.9% and 3.1%, respectively.
The increases in 1997 and 1996 retail energy sales were primarily due to the
strength of business and economic conditions in the company's service area.
Residential energy sales experienced a decline as a result of milder than normal
weather in 1997, compared to relatively normal weather in 1996. Assuming normal
weather, sales to retail customers are projected to grow approximately 2.3
percent annually on average during 1998 through 2003.
Expenses
Total operating expenses of $2.5 billion for 1997 were up $18 million or 0.7
percent compared with the prior year. This increase was primarily due to a $19
million increase in fuel costs and a $10 million increase in depreciation and
amortization expense. These increases were somewhat offset by a $16 million
decrease in maintenance expenses.
Total operating expenses of $2.5 billion for 1996 were up $105 million or
4.4 percent compared with 1995. The major components of this increase include
$85 million in fuel costs, $15 million in maintenance expense, and $17 million
in depreciation and amortization offset by a decrease in purchased power of $15
million.
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 KWH generated were as follows:
--------------------------
1997 1996 1995
--------------------------
Total generation
(billions of KWHs) 65 65 58
Sources of generation
(percent) --
Coal 72 72 73
Nuclear 20 20 19
Hydro 8 8 8
Average cost of fuel per net
KWH generated
(cents) --
Coal 1.73 1.71 1.71
Nuclear 0.54 0.50 0.50
Total 1.49 1.46 1.48
--------------------------------------------------------------
Note: Oil & Gas comprise less than 1% of generation.
Fuel expense increased in 1997 by $19 million or 2.2 percent. This increase
can be attributed to slightly higher generation and fuel costs. Fuel expense
increased in 1996 by $85 million or 10.8 percent. This increase can be
attributed to higher generation.
Purchased power consists primarily of purchases from the affiliates of the
Southern electric system. Purchased power transactions among the company and its
II-59
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 1997 Annual Report
affiliates will vary from period to period depending on demand, the
availability, and the variable production cost of generating resources at each
company. Total KWH purchases increased 12.4 percent from the prior year.
The 6.1 percent decrease in maintenance expenses in 1997 is attributable
primarily to a decrease in distribution expenses. The increase in maintenance
expenses for 1996 is due to increased nuclear expenses, primarily outage related
accruals.
Depreciation and amortization expense increased 3.2 percent in 1997 and 5.6
percent in 1996. These increases reflect additions to utility plant.
Total net interest and other charges increased $25.4 million (11.2 percent)
in 1997 primarily due to an increase in company obligated mandatorily redeemable
preferred securities outstanding. This increase was offset by a $12 million
(45.2 percent) decrease in dividends on preferred stock. The decline in net
interest and other charges in 1996 by $11 million (4.5 percent) was due
primarily to a charge of $10 million in 1995 to the amortization of debt
discount, premium, and expense net, pursuant to an Alabama Public Service
Commission (APSC) order. See Note 3 to the financial statements under "Retail
Rate Adjustment Procedures" for additional details.
Effects of Inflation
The company is subject to rate regulation and income tax laws that are based on
the recovery of historical costs. Therefore, inflation creates an economic loss
because the company is recovering its costs of investments in dollars that have
less purchasing power. While the inflation rate has been relatively low in
recent years, it continues to have an adverse effect on the company because of
the large investment in long-lived utility plant. Conventional accounting for
historical cost does not recognize this economic loss nor the partially
offsetting gain that arises through financing facilities with fixed-money
obligations, such as long-term debt and preferred stock. Any recognition of
inflation by regulatory authorities is reflected in the rate of return allowed.
Future Earnings Potential
The results of operations for the past three years are not necessarily
indicative of future earnings potential. The level of future earnings depends on
numerous factors ranging from energy sales growth to a less regulated more
competitive environment.
The company currently operates as a vertically integrated utility providing
electricity to customers within its traditional service area located in the
state of Alabama. Prices for electricity provided by the company to retail
customers are set by the APSC under cost-based regulatory principles.
Future earnings in the near term will depend upon growth in electric sales,
which are subject to a number of factors. Traditionally, these factors have
included weather, competition, changes in contracts with neighboring utilities,
energy conservation practiced by customers, the elasticity of demand, and the
rate of economic growth in the company's service area. However, the Energy
Policy Act of 1992 (Energy Act) is having a dramatic effect on the future of the
electric utility industry. The Energy Act promotes energy efficiency,
alternative fuel use, and increased competition for electric utilities. The
company is positioning the business to meet the challenge of this major change
in the traditional practice of selling electricity. The Energy Act allows
independent power producers (IPPs) to access a utility's transmission network in
order to sell electricity to other utilities. This enhances the incentive for
IPPs to build cogeneration plants for a utility's large industrial and
commercial customers and sell excess energy generation to other utilities. Also,
electricity sales for resale rates are being driven down by wholesale
transmission access and numerous potential new energy suppliers, including power
marketers and brokers. The company is aggressively working to maintain and
expand its share of wholesale business in the Southeastern power markets.
Although the Energy Act does not permit retail customer access, it was a
major catalyst for the current restructuring and consolidation taking place
within the utility industry. Numerous federal and state initiatives are in
varying stages to promote wholesale and retail competition. Among other things,
these initiatives allow customers to choose their electricity provider. As these
initiatives materialize, the structure of the utility industry could radically
II-60
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 1997 Annual Report
change. Some states have approved initiatives that result in a separation of the
ownership and/or operation of generating facilities from the ownership and/or
operation of transmission and distribution facilities. While various
restructuring and competition initiatives have been or are being discussed in
Alabama, Florida, Georgia, and Mississippi, none have been enacted to date.
Enactment would require numerous issues to be resolved, including significant
ones relating to transmission pricing and recovery of any stranded investments.
The inability of the company to recover its investments, including the
regulatory assets described in Note 1 to the financial statements, could have a
material adverse effect on the financial condition of the company. The company
is attempting to minimize or reduce stranded cost exposure.
Continuing to be a low-cost producer could provide opportunities to increase
market share and profitability in markets that evolve with changing regulation.
Conversely, 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.
Rates to retail customers served by the company are regulated by the APSC.
Rates for the company can be adjusted periodically within certain limitations
based on earned retail rate of return compared with an allowed return. In June
1995, the APSC issued an order granting the company's request for gradual
adjustments to move toward parity among customer classes. This order also calls
for a moratorium on any periodic retail rate increases (but not decreases) until
2001.
In December 1995, the APSC issued an order authorizing the company to reduce
balance sheet items -- such as plant and deferred charges -- at any time the
company's actual base rate revenues exceed the budgeted revenues. In April 1997,
the APSC issued an additional order authorizing the company to reduce balance
sheet asset items. This order authorizes the reduction of such items up to an
amount equal to five times the total estimated annual revenue reduction
resulting from future rate reductions initiated by the company. See Note 3 to
the financial statements for information about this and other matters.
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 Financial Accounting Standards
Board (FASB) has decided to review the accounting for liabilities related to
closure and removal of long-lived assets, including nuclear decommissioning. If
the FASB issues new accounting rules, the estimated costs of closing and
removing the company's nuclear and other facilities may be required to be
recorded as liabilities in the Balance Sheets. Also, the annual provisions for
such costs could change. Because of the company's current ability to recover
closure and removal costs through rates, these changes would not have a
significant adverse effect on results of operations. See Note 1 to the financial
statements under "Depreciation and Nuclear Decommissioning" for additional
information.
The company is heavily dependent upon complex computer systems for all
phases of its operations. The year 2000 issue -- common to most corporations
--concerns the inability of certain software and databases to properly recognize
date sensitive information related to the year 2000 and thereafter. This problem
could result in a material disruption to the company's operations, if not
corrected. The company has assessed and developed a detailed strategy to prevent
or at least minimize problems related to the year 2000 issue. In 1997 resources
were committed and implementation began to modify the affected information
systems. Total costs related to the project are estimated to be approximately
$26 million, of which $2.1 million was spent in 1997. The remaining costs will
be expensed primarily in 1998. Implementation is currently on schedule.
Although, the degree of success of this project cannot be determined at this
time, management believes there will be no significant effect on the company's
operations.
The company is involved in various matters being litigated. See Note 3 to
the financial statements for information regarding material issues that could
possibly affect future earnings.
Compliance costs related to current and future environmental laws and
regulations could affect earnings if such costs are not fully recovered. The
Clean Air Act and other important environmental items are discussed later under
"Environmental Matters."
II-61
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 1997 Annual Report
The company is subject to the provisions of 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 that are not specifically recoverable, and determine if any other
assets have been impaired. See Note 1 to the financial statements under
"Regulatory Assets and Liabilities" for additional information.
Exposure to Market Risk
Due to cost-based rate regulation, the company has limited exposure to market
volatility in interest rates and prices of electricity. To mitigate residual
risks relative to movements in electricity prices, the company enters into fixed
price contracts for the purchase and sale of electricity through the wholesale
electricity market. Realized gains and losses are recognized in the income
statement as incurred. At December 31, 1997, exposure from these activities was
not material to the company's financial position, results of operations, or cash
flows.
New Accounting Standards
The FASB has issued Statement No. 130, Reporting Comprehensive Income, which
will be effective in 1998. This statement establishes standards for reporting
and display of comprehensive income and its components in a full set of general
purpose financial statements. The objective of the statement is to report a
measure of all changes in equity of an enterprise that result from transactions
and other economic events of the period other than transactions with owners
(comprehensive income). Comprehensive income is the total of net income and all
other nonowner changes in equity. The company will adopt this statement in 1998.
The FASB has issued Statement No. 131, Disclosure about Segments of an
Enterprise and Related Information. This statement requires that a public
business enterprise report financial and descriptive information about its
reportable operating segments. Generally, financial information is required to
be reported on the basis that it is used by the chief operating decision maker
in deciding how to allocate resources and in assessing performance. This
statement also establishes standards for related disclosures about products and
services, geographic areas, and major customers. The company adopted the new
rules in 1997, and they did not have a significant impact on the company's
financial reporting. However, this conclusion may change as industry
restructuring and competitive factors influence the company's operations.
FINANCIAL CONDITION
Overview
The company's financial condition remained stable in 1997. This stability is the
continuation over recent years of growth in energy sales and cost control
measures combined with a significant lowering of the cost of capital, achieved
through the refinancing and/or redemption of higher-cost long-term debt and
preferred stock.
The company had gross property additions of $451 million in 1997. The
majority of funds needed for gross property additions for the last several years
have been provided from operating activities, principally from earnings and
non-cash charges to income such as depreciation and deferred income taxes. The
Statements of Cash Flows provide additional details.
Capital Structure
The company's ratio of common equity to total capitalization -- including
short-term debt -- was 44.7 percent in 1997, compared with 45.3 percent in 1996,
and 45.0 percent in 1995.
In January 1997, Alabama Power Capital Trust II (Trust II), of which the
company owns all of the common securities, issued $200 million of 7.60 percent
mandatorily redeemable preferred securities. Substantially all of the assets of
Trust II are $206 million aggregate principal amount of the company's 7.60
percent junior subordinated notes due December 31, 2036.
During 1997, the company redeemed $162.0 million of preferred stock and
reacquired an additional $22.9 million through tender offer.
II-62
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 1997 Annual Report
The company's current securities ratings are as follows:
Duff & Standard
Phelps Moody's & Poor's
----------------------------------
First Mortgage Bonds AA- A1 A+
Company Obligated
Mandatorily
Redeemable
Preferred Securities A+ a2 A
Preferred Stock A+ a2 A
------------------------------------------------------------
Capital Requirements
Capital expenditures are estimated to be $615 million for 1998, $723 million for
1999, and $524 million for 2000. The total is $1.9 billion for the three years.
Actual capital costs may vary from this estimate because of factors such as
changes in business conditions; revised load growth projections; changes in
environmental regulations; changes in the existing nuclear plant to meet new
regulatory requirements; increasing cost of labor, equipment, and materials; and
cost of capital. In addition, there can be no assurance that costs related to
capital expenditures will be fully recovered.
The company will replace all six steam generators at Plant Farley at a total
cost of approximately $234 million. Additionally, the company plans to construct
and install 800 megawatts of new generating capacity and associated substation
facilities at Plant Barry. The projected capital expenditures for this project
amount to approximately $289 million.
Other Capital Requirements
In addition to the funds needed for the capital budget, approximately $320
million will be required by the end of 2000 for maturities of first mortgage
bonds. Also, the company will continue to retire higher-cost debt and preferred
stock and replace these obligations with lower-cost capital if market conditions
permit.
Environmental Matters
In November 1990, the Clean Air Act was signed into law. Title IV of the Clean
Air Act -- the acid rain compliance provision of the law - significantly
impacted the operating companies of Southern Company, including Alabama Power.
Specific reductions in sulfur dioxide and nitrogen oxide emissions from
fossil-fired generating plants are required in two phases. Phase I compliance
began in 1995 and initially affected 28 generating units of Southern Company. As
a result of Southern Company's compliance strategy, an additional 22 generating
units were brought into compliance with Phase I requirements. Phase II
compliance is required in 2000, and all fossil-fired generating plants will be
affected.
Southern Company achieved Phase I sulfur dioxide compliance at the affected
plants by switching to low-sulfur coal, which required some equipment upgrades.
Construction expenditures for Phase I compliance totaled approximately $25
million for the company.
For Phase II sulfur dioxide compliance, the company could use emission
allowances, increase fuel switching, and/or install flue gas desulfurization
equipment at selected plants. Also equipment to control nitrogen oxide emissions
will be installed on additional system fossil-fired units as necessary to meet
Phase II limits. Current compliance strategy for Phase II could require total
estimated construction expenditures of approximately $33 million, of which $27
million remains to be spent.
A significant portion of costs related to the acid rain provision of the
Clean Air Act is expected to be recovered through existing ratemaking
provisions. However, there can be no assurance that all Clean Air Act costs will
be recovered.
In July 1997, the Environmental Protection Agency (EPA) revised the national
ambient air quality standards for ozone and particulate matter. This revision
makes the standards significantly more stringent. Also, in October 1997, the EPA
issued a proposed regional ozone rule that --if implemented--could require
substantial further reductions in NOx emissions from fossil-fueled generating
facilities. Implementation of the standards and the proposed rule could result
in significant additional compliance costs and capital expenditures that cannot
be determined at this time.
The EPA and state environmental regulatory agencies are reviewing and
evaluating various other matters including: emission control strategies for
ozone nonattainment areas; additional controls for hazardous air pollutant
emissions; and hazardous waste disposal requirements. The impact of new
standards will depend on the development and implementation of applicable
regulations.
II-63
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 1997 Annual Report
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. The company
conducts studies to determine the extent of any required cleanup costs and has
recognized in the financial statements costs to clean up known sites.
Several major pieces of environmental legislation are being considered for
reauthorization or amendment by Congress. These include: the Clean Air Act; the
Clean Water Act; the Comprehensive Environmental Response, Compensation, and
Liability Act; the Resource Conservation and Recovery Act; the Toxic Substances
Control Act; and the Endangered Species Act. Changes to these laws could affect
many areas of Southern Company's operations. The full impact of any such changes
cannot be determined at this time.
Compliance with possible additional legislation related to global climate
change, electromagnetic fields, and other environmental and health concerns
could significantly affect Southern 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.
Sources of Capital
The company historically has relied on issuances of first mortgage bonds and
preferred stock, in addition to pollution control revenue bonds issued for its
benefit by public authorities, to meet its long-term external financing
requirements. Recently, the company's financings have consisted of unsecured
debt and trust preferred securities. In this regard, the company sought and
obtained stockholder approval in 1997 to amend its corporate charter eliminating
restrictions on the amounts of unsecured indebtedness it may incur. To issue
additional debt and equity securities, the company must comply with certain
earnings coverage requirements designated in its mortgage indenture and
corporate charter. The company's coverages are at a level that would permit any
necessary amount of security sales at current interest and dividend rates.
As required by the Nuclear Regulatory Commission and as ordered by the APSC,
the company has established external trust funds for nuclear decommissioning
costs. In 1994, the company also established an external trust fund for
postretirement benefits as ordered by the APSC. The cumulative effect of funding
these items over a long period will diminish internally funded capital and may
require capital from other sources. For additional information concerning
nuclear decommissioning costs, see Note 1 to the financial statements under
"Depreciation and Nuclear Decommissioning."
Cautionary Statement Regarding Forward-Looking Information
The company's 1997 Annual Report contains forward-looking statements in addition
to historical information. The company cautions that there are various important
factors that could cause actual results to differ materially from those
indicated in the forward-looking statements; accordingly, there can be no
assurance that such indicated results will be realized. These factors include
legislative and regulatory initiatives regarding deregulation and restructuring
of the electric utility industry; the extent and timing of the entry of
additional competition in the company's markets; potential business strategies
-- including acquisitions or dispositions of assets or internal restructuring
--that may be pursued by Southern Company; state and federal rate regulation;
changes in or application of environmental and other laws and regulations to
which the company is subject; political, legal and economic conditions and
developments; financial market conditions and the results of financing efforts;
changes in commodity prices and interest rates; weather and other natural
phenomena; and other factors discussed in the reports--including Form
10-K--filed from time to time by the company with the Securities and Exchange
Commission.
II-64
II-65
II-66
II-67
II-68
II-69
II-70
NOTES TO FINANCIAL STATEMENTS
Alabama Power Company 1997 Annual Report
1. SUMMARY OF SIGNIFICANT ACCOUNTING
POLICIES
General
Alabama Power Company (the company) is a wholly owned subsidiary of Southern
Company, which is the parent company of five operating companies, a system
service company, Southern Communications Services (Southern Communications),
Southern Energy, Inc. (Southern Energy), Southern Nuclear Operating Company
(Southern Nuclear), Southern Company Energy Solutions, and other direct and
indirect subsidiaries. The operating companies (Alabama Power Company, Georgia
Power Company, Gulf Power Company, Mississippi Power Company, and Savannah
Electric and Power Company) provide electric service in four southeastern
states. Contracts among the companies -- dealing with jointly-owned generating
facilities, interconnecting transmission lines, and the exchange of electric
power -- are regulated by the Federal Energy Regulatory Commission (FERC) or the
Securities and Exchange Commission (SEC). The system service company provides,
at cost, specialized services to Southern Company and subsidiary companies.
Southern Communications provides digital wireless communications services to the
operating companies and also markets these services to the public within the
Southeast. Southern Energy designs, builds, owns and operates power production
and delivery facilities and provides a broad range of energy related services in
the United States and international markets. Southern Nuclear provides services
to Southern Company's nuclear power plants. Southern Company Energy Solutions
develops new business opportunities related to energy products and services.
Southern Company is registered as a holding company under the Public Utility
Holding Company Act of 1935 (PUHCA). Both Southern Company and its subsidiaries
are subject to the regulatory provisions of the PUHCA. The company is also
subject to regulation by the FERC and the Alabama Public Service Commission
(APSC). The company follows generally accepted accounting principles and
complies with the accounting policies and practices prescribed by the respective
regulatory commissions. The preparation of financial statements in conformity
with generally accepted accounting principles requires the use of estimates, and
the actual results may differ from those estimates.
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 expected to be credited
to customers through the ratemaking process. Regulatory assets and (liabilities)
reflected in the Balance Sheets at December 31 relate to the following:
1997 1996
-----------------------
(in thousands)
Deferred income taxes $ 384,549 $ 410,010
Deferred income tax credits (327,328) (364,792)
Premium on reacquired debt 81,417 84,149
Department of Energy assessments 34,416 37,490
Vacation pay 28,783 28,369
Natural disaster reserve (22,416) (20,757)
Work force reduction costs 19,316 45,969
Other, net 59,726 45,521
----------------------------------------------------------------
Total $ 258,463 $265,959
================================================================
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 net regulatory assets and liabilities that are not specifically
recoverable through regulated rates. In addition, the company would be required
to determine if any impairment to other assets exists, including plant, and
write down the assets, if impaired, to their fair value.
Revenues and Fuel Costs
The company accrues revenues for services rendered but unbilled at the end of
each fiscal period. Fuel costs are expensed as the fuel is used. The company's
electric rates include provisions to adjust billings for fluctuations in fuel
and the energy component of purchased power costs. Revenues are adjusted for
differences between recoverable fuel costs and amounts actually recovered in
current rates.
The company has a diversified base of customers. No single customer or
industry comprises 10 percent or more of revenues. In 1997, uncollectible
II-71
NOTES (continued)
Alabama Power Company 1997 Annual Report
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 $68
million in 1997, $64 million in 1996, and $54 million in 1995. 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 2010 and 2013
at Plant Farley units 1 and 2, respectively.
Also, the Energy Policy Act of 1992 required the establishment in 1993 of a
Uranium Enrichment Decontamination and Decommissioning Fund, which is to be
funded in part by a special assessment on utilities with nuclear plants. This
assessment will be paid over a 15- year period, which began in 1993. This fund
will be used by the DOE for the decontamination and decommissioning of its
nuclear fuel enrichment facilities. The law provides that utilities will recover
these payments in the same manner as any other fuel expense. The company
estimates its remaining liability at December 31, 1997, under this law to be
approximately $34 million. This obligation is recognized in the accompanying
Balance Sheets.
Depreciation and Nuclear Decommissioning
Depreciation of the original cost of depreciable utility plant in service is
provided primarily by using composite straight-line rates, which approximated
3.3 percent in 1997 and 1996, and 3.2 percent in 1995. 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 cost
of decommissioning nuclear facilities and removal of other facilities.
In 1988, the Nuclear Regulatory Commission (NRC) adopted regulations
requiring all licensees operating commercial power reactors to establish a plan
for providing, with reasonable assurance, funds for decommissioning. 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 periods approved by the APSC. The NRC's minimum
external funding requirements are based on a generic estimate of the cost to
decommission the radioactive portions of a nuclear unit based on the size and
type of reactor. The company has filed plans with the NRC to ensure that -- over
time -- the deposits and earnings of the external trust funds will provide the
minimum funding amounts prescribed by the NRC.
Site study cost is the estimate to decommission the facility as of the
site study year, and ultimate cost is the estimate to decommission the facility
as of retirement date. The estimated costs of decommissioning -- both site study
costs and ultimate costs -- at December 31, 1997, for Plant Farley were as
follows:
Site study basis (year) 1993
Decommissioning periods:
Beginning year 2017
Completion year 2029
-----------------------------------------------------------
(in millions)
Site study costs:
Radiated structures $ 489
Non-radiated structures 89
-----------------------------------------------------------
Total $ 578
===========================================================
(in millions)
Ultimate costs:
Radiated structures $1,504
Non-radiated structures 274
-----------------------------------------------------------
Total $1,778
===========================================================
(in millions)
Amount expensed in 1997 $ 18
-----------------------------------------------------------
Accumulated provisions:
Balance in external trust funds $ 193
Balance in internal reserves 44
-----------------------------------------------------------
Total $ 237
===========================================================
Significant assumptions:
Inflation rate 4.5%
Trust earning rate 7.0
-----------------------------------------------------------
Annual provisions for nuclear decommissioning are based on an annuity method
as approved by the APSC. All of the company's decommissioning costs are approved
for ratemaking.
II-72
NOTES (continued)
Alabama Power Company 1997 Annual Report
The decommissioning cost estimates are based on prompt dismantlement and
removal of the plant from service. The actual decommissioning costs may vary
from the above estimates because of changes in the assumed date of
decommissioning, changes in NRC requirements, or changes in the assumptions used
in making estimates.
Income Taxes
The company uses the liability method of accounting for deferred income taxes
and provides deferred income taxes for all significant income tax temporary
differences. Investment tax credits utilized are deferred and amortized to
income over the average lives of the related property.
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. The composite rate used to determine the amount of
allowance was 5.8 percent in 1997 and 1996, and 7.1 percent in 1995. AFUDC, net
of income tax, as a percent of net income after dividends on preferred stock was
0.8 percent in 1997, 1.1 percent in 1996 and 1.7 percent in 1995.
Utility Plant
Utility plant is stated at original cost. Original cost includes: materials;
labor; minor items of property; appropriate administrative and general costs;
payroll-related costs such as taxes, pensions, and other benefits; and the
estimated cost of funds used during construction. The cost of maintenance,
repairs and replacement of minor items of property is charged to maintenance
expense. The cost of replacements of property (exclusive of minor items of
property) is charged to utility plant.
Financial Instruments
The company's only financial instruments for which the carrying amount did not
approximate fair value at December 31 are as follows:
Carrying Fair
Amount Value
-------------------------
(in millions)
Long-term debt:
At December 31, 1997 $2,541 $2,638
At December 31, 1996 $2,367 $2,420
Preferred Securities:
At December 31, 1997 297 300
At December 31, 1996 97 94
------------------------------------------------------------
The fair value for long-term debt and preferred securities was 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.
Natural Disaster Reserve
In September 1994, in response to a request by the company, the APSC issued an
order allowing the company to establish a Natural Disaster Reserve. Regulatory
treatment allows the company to accrue $250 thousand per month, until the
maximum accumulated provision of $32 million is attained. However, in December
1995, the APSC approved higher accruals to restore the reserve to its authorized
level whenever the balance in the reserve declines below $22.4 million.
2. RETIREMENT BENEFITS
Pension Plan
The company has a defined benefit, trusteed, non-contributory pension plan that
covers substantially all regular employees. Benefits are based on one of the
following formulas: years of service and final average pay or years of service
and a flat-dollar benefit. The company uses the "entry age normal method with a
frozen initial liability" actuarial method for funding purposes, subject to
limitations under federal income tax regulations. Amounts funded to the pension
trusts are primarily invested in equity and fixed-income securities. FASB
Statement No. 87, Employers' Accounting for Pensions, requires use of the
II-73
NOTES (continued)
Alabama Power Company 1997 Annual Report
"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 these employees may become eligible for
these benefits when they retire. Amounts funded are primarily invested in debt
and equity securities. In December 1993, the APSC issued an accounting policy
statement which requires the company to externally fund net annual
postretirement benefits.
FASB Statement No. 106, Employers' Accounting for Postretirement Benefits
Other Than Pensions, requires that medical care and life insurance benefits for
retired employees be accounted for on an accrual basis using a specified
actuarial method, "benefit/years-of-service."
Funded Status and Cost of Benefits
The funded status of the plans and reconciliation to amounts reflected in the
Balance Sheets at December 31 are as follows:
Pension
-------------------
1997 1996
-------------------
(in millions)
Actuarial present value of
benefit obligations:
Vested benefits $ 626 $ 603
Non-vested benefits 22 30
---------------------------------------------------------
Accumulated benefit obligation 648 633
Additional amounts related to
projected salary increases 165 180
----------------------------------------------------------
Projected benefit obligation 813 813
Less:
Fair value of plan assets 1,521 1,334
Unrecognized net gain (585) (413)
Unrecognized prior service cost 43 46
Unrecognized transition asset (35) (40)
----------------------------------------------------------
Prepaid asset recognized in the
Balance Sheets $ 131 $ 114
==========================================================
Postretirement
Benefits
----------------------
1997 1996
----------------------
(in millions)
Actuarial present value of
benefit obligation:
Retirees and dependents $135 $116
Employees eligible to retire 24 28
Other employees 93 98
-----------------------------------------------------------
Accumulated benefit obligation 252 242
Less:
Fair value of plan assets 135 108
Unrecognized net loss 3 15
Unrecognized transition
obligation 61 65
-----------------------------------------------------------
Accrued liability recognized
in the Balance Sheets $ 53 $ 54
===========================================================
The weighted average rates assumed in the actuarial calculations were:
1997 1996 1995
-------------------------------
Discount 7.5% 7.8% 7.3%
Annual salary increase 5.0 5.3 4.8
Long-term return on
plan assets 8.5 8.5 8.5
----------------------------------------------------------
An additional assumption used in measuring the accumulated postretirement
benefit obligation was a weighted average medical care cost trend rate of 8.8
percent for 1997, decreasing gradually to 5.5 percent through the year 2005 and
remaining at that level thereafter. An annual increase in the assumed medical
care cost trend rate of 1 percent would increase the accumulated benefit
obligation as of December 31, 1997, by $21 million and the aggregate of the
service and interest cost components of the net retiree cost by $2 million.
Components of the plans' net cost are shown below:
Pension
-------------------------------------------------------------------
1997 1996 1995
-----------------------------
(in millions)
Benefits earned during
the year $ 20.3 $ 21.5 $ 21.2
Interest cost on projected
benefit obligation 58.4 59.5 54.3
Actual (return) loss on plan
assets (227.8) (148.9) (236.3)
Net amortization and deferral 116.8 43.8 136.9
-------------------------------------------------------------------
Net pension cost (income) $ (32.3) $ (24.1) $ (23.9)
=====================================================================
II-74
NOTES (continued)
Alabama Power Company 1997 Annual Report
Of the above net pension income, $24.8 million in 1997, $20.3 million
in 1996, and $17.1 million in 1995 were recorded as credits to operating
expenses, and the remainder was recorded as credits to construction and other
accounts.
Postretirement
Benefits
--------------------
1997 1996 1995
------------- ------
(in millions)
Benefits earned during the year $ 4 $ 5 $ 7
Interest cost on accumulated
benefit obligation 18 17 18
Amortization of transition
obligation 4 4 7
Actual (return) loss on plan
assets (14) (7) (10)
Net amortization and deferral 7 2 5
-------------------------------------------------------------
Net postretirement costs $ 19 $ 21 $ 27
=============================================================
Of the above net postretirement costs recorded, $16.3 million in 1997, $17.8
million in 1996, and $22.7 million in 1995 were charged to operating expenses
and the remainder was charged to construction and other accounts.
Work Force Reduction Programs
The company has incurred additional costs for work force reduction programs. The
costs related to these programs were $33 million, $26.7 million and $14.3
million for the years 1997, 1996 and 1995, respectively. In addition, certain
costs of these programs were deferred and are being amortized in accordance with
regulatory treatment. The unamortized balance of these costs was $19.3 million
at December 31, 1997.
3. LITIGATION AND REGULATORY MATTERS
Retail Rate Adjustment Procedures
In November 1982, the APSC adopted rates that provide for periodic adjustments
based upon the company's earned return on end-of-period retail common equity.
The rates also provide for adjustments to recognize the placing of new
generating facilities in retail service. Both increases and decreases have been
placed into effect since the adoption of these rates. The rate adjustment
procedures allow a return on common equity range of 13.0 percent to 14.5 percent
and limit increases or decreases in rates to 4 percent in any calendar year.
In June 1995, the APSC issued a rate order granting the company's request
for gradual adjustments to move toward parity among customer classes. This order
also calls for a moratorium on any periodic retail rate increases (but not
decreases) until July 2001.
In December 1995, the APSC issued an order authorizing the company to reduce
balance sheet items -- such as plant and deferred charges -- at any time the
company's actual base rate revenues exceed the budgeted revenues. In April 1997,
the APSC issued an additional order authorizing the company to reduce balance
sheet asset items. This order authorizes the reduction of such items up to an
amount equal to five times the total estimated annual revenue reduction
resulting from future rate reductions initiated by the company.
The ratemaking procedures will remain in effect until the APSC votes to
modify or discontinue them.
Appliance Warranty Litigation
In 1996, legal actions against the company were filed in several counties in
Alabama charging the company with fraud and non-compliance with regulatory
statutes relating to the offer, sale, and financing of "extended service
contracts" in connection with the sale of electric appliances. Some of these
suits were filed as class actions, while others were filed on behalf of multiple
individual plaintiffs. The plaintiffs seek damages for an unspecified amount.
The company has offered extended service agreements to its customers since
January 1984, and approximately 175,000 extended service agreements could be
involved in these proceedings. The final outcome of these cases cannot now be
determined.
FERC Reviews Equity Returns
In May 1991, the FERC ordered that hearings be conducted concerning the
reasonableness of the operating companies' wholesale rate schedules and
contracts that have a return on common equity of 13.75 percent or greater. The
contracts that could be affected by the hearings include substantially all of
the transmission, unit power, long-term power and other similar contracts.
In August 1992, a FERC administrative law judge issued an opinion that
changes in rate schedules and contracts were not necessary and that the FERC
II-75
NOTES (continued)
Alabama Power Company 1997 Annual Report
staff failed to show how any changes were in the public interest. The FERC staff
has filed exceptions to the administrative law judge's opinion, and the matter
remains pending before the FERC.
In August 1994, the FERC instituted another proceeding based on
substantially the same issues as in the 1991 proceeding. In November 1995, a
FERC administrative law judge issued an opinion that the FERC staff failed to
meet its burden of proof, and therefore, no change in the equity return was
necessary. The FERC staff has filed exceptions to the administrative law judge's
opinion, and the matter is pending before the FERC.
If the rates of return on common equity recommended by the FERC staff were
applied to all of the schedules and contracts involved in both proceedings, as
well as certain other contracts that reference these proceedings in determining
return on common equity, and if refunds were ordered, the amount of refunds
could range up to approximately $194 million at December 31, 1997 for Southern
Company, of which the company's portion would be approximately $95 million.
Although management believes that rates are not excessive and that refunds are
not justified, the final outcome of this matter cannot now be determined.
Tax Litigation
In August 1997, Southern Company and the Internal Revenue Service entered into a
settlement agreement related to tax issues for the years 1984 through 1987. The
agreement is subject to the review and approval by the Joint Congressional
Committee on Taxation. If approved by the Joint Committee, the agreement would
resolve all issues in the case for the years before the U. S. Tax Court,
resulting in a refund to the company of approximately $22 million. This amount
includes interest of $14 million. The tax litigation was related to a timing
issue as to when taxes should have been paid; therefore, only the interest
portion will affect future income.
4. CAPITAL BUDGET
The company's capital expenditures are currently estimated to total $615 million
in 1998, $723 million in 1999, and $524 million in 2000. The capital budget is
subject to periodic review and revision, and actual capital cost incurred may
vary from the above estimates because of numerous factors. These factors
include: changes in business conditions; revised load growth projections;
changes in environmental regulations; changes in the existing nuclear plant to
meet new regulatory requirements; increasing costs of labor, equipment, and
materials; and cost of capital.
The company will replace all six steam generators at Plant Farley at a total
cost of approximately $234 million. Additionally, the company plans to construct
and install 800 megawatts of new generating capacity and associated substation
facilities at Plant Barry. The projected capital expenditures for this project
amount to approximately $289 million.
In addition, significant construction will continue related to transmission
and distribution facilities and the upgrading of generating plants.
5. FINANCING, INVESTMENT, AND
COMMITMENTS
General
To the extent possible, the company's construction program is expected to be
financed primarily from internal sources. Short-term debt is often utilized and
the amounts available are discussed below. The company may issue additional
long-term debt and preferred securities for debt maturities, redeeming
higher-cost securities, and meeting additional capital requirements.
Financing
The ability of the company to finance its capital budget depends on the amount
of funds generated internally and the funds it can raise by external financing.
The company historically has relied on issuances of first mortgage bonds and
preferred stock, in addition to pollution control revenue bonds issued for its
benefit by public authorities, to meet its long-term external financing
requirements. Recently, the company's financings have consisted of unsecured
debt and trust preferred securities. In this regard, the company sought and
obtained stockholder approval in 1997 to amend its corporate charter eliminating
restrictions on the amounts of unsecured indebtedness it may incur. In order to
issue additional debt and equity securities, the company must comply with
II-76
NOTES (continued)
Alabama Power Company 1997 Annual Report
certain earnings coverage requirements designated in its mortgage indenture and
corporate charter. The most restrictive of these provisions requires, for the
issuance of additional first mortgage bonds, that before-income-tax earnings, as
defined, cover pro forma annual interest charges on outstanding first mortgage
bonds at least twice; and for the issuance of additional preferred stock, that
gross income available for interest cover pro forma annual interest charges and
preferred stock dividends at least one and one-half times. The company's
coverages are at a level that would permit any necessary amount of security
sales at current interest and dividend rates.
Bank Credit Arrangements
The company, along with Georgia Power Company, has entered into agreements with
several banks outside the service area to provide $300 million of revolving
credit to the companies through June 30, 1999. To provide liquidity support for
commercial paper programs, the company and Georgia Power Company have exclusive
right to $135 million and $165 million, respectively, of the available credit.
However, the allocations can be changed among the borrowers by notifying the
respective banks. The companies have the option of converting the short-term
borrowings into term loans, payable in 12 equal quarterly installments, with the
first installment due at the end of the first calendar quarter after the
applicable termination date or at an earlier date at 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.
Additionally, the company maintains committed lines of credit in the amount
of $679 million (including $208 million of such lines under which borrowings may
be made only to fund purchase obligations relating to variable rate pollution
control bonds) which expire at various times during 1998 and, in certain cases,
provide for average annual compensating balances. Because the arrangements are
based on an average balance, the company does not consider any of its cash
balances to be restricted as of any specific date. Moreover, the company borrows
from time to time pursuant to arrangements with banks for uncommitted lines of
credit.
At December 31, 1997, the company had regulatory approval to have
outstanding up to $750 million of short-term borrowings.
Assets Subject to Lien
The company's mortgage, 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.
Fuel Commitments
To supply a portion of the fuel requirements of its generating plants, the
company has entered into various long-term commitments for the procurement of
fossil and nuclear fuel. In most cases, these contracts contain provisions for
price escalations, minimum purchase levels and other financial commitments.
Total estimated long-term obligations at December 31, 1997, were as follows:
Year Amounts
---- -----------------
(in millions)
1998 $869
1999 632
2000 388
2001 377
2002 317
2003-2013 2,538
-------------------------------------------------------------
Total commitments $5,121
=============================================================
Operating Leases
The company has entered into coal rail car rental agreements with various terms
and expiration dates. At December 31, 1997, estimated minimum rental commitments
for noncancellable operating leases were as follows:
Year Amounts
---- -----------------
(in millions)
1998 $5.6
1999 5.6
2000 5.6
2001 5.6
2002 5.6
2003-2017 55.5
------------------------------------------------------------------
Total minimum payments $83.5
==================================================================
6. JOINT OWNERSHIP AGREEMENTS
The company and Georgia Power Company own equally all of the outstanding capital
stock of Southern Electric Generating Company (SEGCO), which owns electric
II-77
NOTES (continued)
Alabama Power Company 1997 Annual Report
generating units with a total rated capacity of 1,020 megawatts, together with
associated transmission facilities. The capacity of these units is sold equally
to the company and Georgia Power Company under a contract which, in substance,
requires payments sufficient to provide for the operating expenses, taxes,
interest expense and a return on equity, whether or not SEGCO has any capacity
and energy available. The company's share of expenses totaled $73 million in
1997, $75 million in 1996 and $71 million in 1995, and is included in "Purchased
power from affiliates" in the Statements of Income.
In addition, the company has guaranteed unconditionally the obligation of
SEGCO under an installment sale agreement for the purchase of certain pollution
control facilities at SEGCO's generating units, pursuant to which $24.5 million
principal amount of pollution control revenue bonds are outstanding. Georgia
Power Company has agreed to reimburse the company for the pro rata portion of
such obligation corresponding to its then proportionate ownership of stock of
SEGCO if the company is called upon to make such payment under its guaranty.
At December 31, 1997, the capitalization of SEGCO consisted of $50 million
of equity and $72 million of long-term debt on which the annual interest
requirement is $4.5 million. SEGCO paid dividends totaling $10.6 million in
1997, $10.1 million in 1996, and $7.6 million in 1995, of which one-half of each
was paid to the company. SEGCO's net income was $8.5 million, $7.7 million, and
$8.1 million for 1997, 1996 and 1995, respectively.
The company's percentage ownership and investment in jointly-owned
generating plants at December 31, 1997, follows:
Total
Megawatt Company
Facility (Type) Capacity Ownership
------------------- ------------ -------------
Greene County 500 60.00% (1)
(coal)
Plant Miller
Units 1 and 2 1,320 91.84% (2)
(coal)
=========================================================
(1) Jointly owned with an affiliate, Mississippi Power Company.
(2) Jointly owned with Alabama Electric Cooperative, Inc.
Company Accumulated
Facility Investment Depreciation
------------------- -------------- ---------------
(in millions)
Greene County $ 93 $ 40
Plant Miller
Units 1 and 2 717 311
------------------------------------------------------------
7. LONG-TERM POWER SALES AGREEMENTS
General
The company and the operating affiliates of Southern Company have entered into
long-term contractual agreements for the sale of capacity and energy to certain
non-affiliated utilities located outside the system's service area. These
agreements -- expiring at various dates discussed below -- are firm and pertain
to capacity related to specific generating units. Because the energy is
generally sold at cost under these agreements, profitability is primarily
affected by revenues from capacity sales. The company's capacity revenues
amounted to $136 million in 1997, $151 million in 1996, and $157 million in
1995.
Unit power from Plant Miller is being sold to Florida Power Corporation
(FPC), Florida Power & Light Company (FP&L), Jacksonville Electric Authority
(JEA) and the City of Tallahassee, Florida. Under these agreements,
approximately 1,200 megawatts of capacity is scheduled to be sold through 1999.
Thereafter, these sales will remain at that approximate level -- unless reduced
by FP&L, FPC, and JEA for the periods after 1999 with a minimum of three years
notice -- until the expiration of the contracts in 2010.
Alabama Municipal Electric Authority (AMEA) Capacity Contracts
In August 1986, the company entered into a firm power purchase contract with
AMEA entitling AMEA to scheduled amounts of capacity (to a maximum 100
megawatts) for a period of 15 years commencing September 1, 1986 (1986
Contract). In October 1991, the company entered into a second firm power
purchase contract with AMEA entitling AMEA to scheduled amounts of additional
capacity (to a maximum 80 megawatts) for a period of 15 years commencing October
1, 1991 (1991 Contract). In both contracts the power will be sold to AMEA for
its member municipalities that previously were served directly by the company as
wholesale customers. Under the terms of the contracts, the company received
II-78
NOTES (continued)
Alabama Power Company 1997 Annual Report
payments from AMEA representing the net present value of the revenues associated
with the respective capacity entitlements, discounted at effective annual rates
of 9.96 percent and 11.19 percent for the 1986 and 1991 contracts, respectively.
These payments are being recognized as operating revenues and the discounts are
being amortized to other interest expense as scheduled capacity is made
available over the terms of the contracts.
In order to secure AMEA's advance payments and the company's performance
obligation under the contracts, the company issued and delivered to an escrow
agent first mortgage bonds representing the maximum amount of liquidated damages
payable by the company in the event of a default under the contracts. No
principal or interest is payable on such bonds unless and until a default by the
company occurs. As the liquidated damages decline under the contracts, a portion
of the bonds equal to the decreases are returned to the company. At December 31,
1997, $113.8 million of such bonds was held by the escrow agent under the
contracts.
8. INCOME TAXES
At December 31, 1997, the tax-related regulatory assets and liabilities were
$385 million and $327 million, respectively. These assets are attributable to
tax benefits flowed through to customers in prior years and to taxes applicable
to capitalized AFUDC. These 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:
1997 1996 1995
------------------------------------
(in thousands)
Total provision for income
taxes:
Federal--
Currently payable $197,159 $172,911 $166,105
Deferred--
current year 32,884 (6,309) 43,493
reversal of prior years (44,300) 18,948 (15,817)
Deferred investment tax
credits - - (75)
------------------------------------------------------------------------
185,743 185,550 193,706
-----------------------------------------------------------------------
State--
Currently payable 23,147 16,212 18,108
Deferred--
current year 1,409 697 5,117
reversal of prior years (2,422) 3,249 (91)
------------------------------------------------------------------------
22,134 20,158 23,134
Total 207,877 205,708 216,840
Less income taxes credited
to other income (12,351) (22,400) (14,142)
-------------------------------------------------------------------------
Total income taxes
charged operations $220,228 $228,108 $230,982
=========================================================================
The tax effects of temporary differences between the carrying amounts of
assets and liabilities in the financial statements and their respective tax
bases, which give rise to deferred tax assets and liabilities, are as follows:
1997 1996
-------------------
(in millions)
Deferred tax liabilities:
Accelerated depreciation $ 847 $ 816
Property basis differences 463 466
Premium on reacquired debt 30 31
Other 31 51
------------------------------------------------------------------
Total 1,371 1,364
------------------------------------------------------------------
Deferred tax assets:
Capacity prepayments 31 34
Other deferred costs 33 27
Postretirement benefits 18 21
Unbilled revenue 16 15
Other 66 54
------------------------------------------------------------------
Total 164 151
------------------------------------------------------------------
Net deferred tax liabilities 1,207 1,213
Portion included in current assets
(liabilities), net (15) (35)
------------------------------------------------------------------
Accumulated deferred income taxes
in the Balance Sheets $1,192 $1,178
===================================================================
II-79
NOTES (continued)
Alabama Power Company 1997 Annual Report
Deferred investment tax credits are amortized over the life of the related
property with such amortization normally applied as a credit to reduce
depreciation in the Statements of Income. Credits amortized in this manner
amounted to $11 million in 1997 and 1996, and $12 million in 1995. At December
31, 1997, all investment tax credits available to reduce federal income taxes
payable had been utilized.
A reconciliation of the federal statutory income tax rate to the effective
income tax rate is as follows:
1997 1996 1995
--------------------------
Federal statutory rate 35.0% 35.0% 35.0%
State income tax,
net of federal deduction 2.4 2.2 2.5
Non-deductible book
depreciation 1.5 1.5 1.6
Differences in prior years'
deferred and current tax rates (2.3) (1.6) (1.8)
Other (1.9) (3.0) (1.4)
--------------------------------------------------------------
Effective income tax rate 34.7% 34.1% 35.9%
==============================================================
Southern Company files a consolidated federal income tax return. Under a
joint consolidated income tax agreement, each subsidiary's current and deferred
tax expense is computed on a stand-alone basis. Tax benefits from losses of the
parent company are allocated to each subsidiary based on the ratio of taxable
income to total consolidated taxable income.
9. COMPANY OBLIGATED MANDATORILY
REDEEMABLE PREFERRED SECURITIES
In January 1996, Alabama Power Capital Trust I (Trust I), of which the company
owns all of the common securities, issued $97 million of 7.375 percent
mandatorily redeemable preferred securities. Substantially all of the assets of
Trust I are $100 million aggregate principal amount of the company's 7.375
percent junior subordinated notes due March 31, 2026.
In January 1997, Alabama Power Capital Trust II (Trust II), of which the
company also owns all of the common securities, issued $200 million of 7.60
percent mandatorily redeemable preferred securities. Substantially all of the
assets of Trust II are $206 million aggregate principal amount of the company's
7.60 percent junior subordinated notes due December 31, 2036.
10. OTHER LONG-TERM DEBT
Details of other long-term debt at December 31 are as follows:
1997 1996
--------------------------
(in thousands)
Obligations incurred in
connection with the
sale of pollution control
revenue bonds by public
authorities-
Collateralized -
5.5% to 6.5 % due
2023-2024 $223,040 $223,040
Variable rates (4.1%
to 4.8% at 1/1/98)
due 2015-2017 89,800 89,800
Non-collateralized -
7.25% due 2003 1,000 1,000
5.8% due 2022 9,800 9,800
Variable rates (4.50%
to 5.9% at 1/1/98)
due 2021 - 2022 217,500 152,500
-------------------------------------------------------------
541,140 476,140
Capitalized lease obligations 7,105 8,056
Long-term senior notes -
7.125% due 2047 193,800 -
-------------------------------------------------------------
Total $742,045 $484,196
=============================================================
Pollution control obligations represent installment purchases of pollution
control facilities financed by funds derived from sales by public authorities of
revenue bonds. The company is required to make payments sufficient for the
authorities to meet principal and interest requirements of such bonds. With
respect to $312.8 million of such pollution control obligations, the company has
authenticated and delivered to the trustees a like principal amount of first
mortgage bonds as security for its obligations under the installment purchase
agreements. No principal or interest on these first mortgage bonds is payable
unless and until a default occurs on the installment purchase agreements.
The estimated aggregate annual maturities of other long-term debt through
2001 are as follows: $1.0 million in 1998, $1.2 million in 1999, $1.1 million in
2000, $1.0 million in 2001 and $1.1 million in 2002.
II-80
NOTES (continued)
Alabama Power Company 1997 Annual Report
11. SECURITIES DUE WITHIN ONE YEAR
A summary of the improvement fund requirements and scheduled maturities and
redemptions of long-term debt and preferred stock due within one year at
December 31 is as follows:
1997 1996
------------------------
(in thousands)
Bond improvement fund
requirements $18,450 $ 19,410
First mortgage bond maturities
and redemptions 55,895 391
Other long-term debt maturities
(Note 10) 991 952
------------------------------------------------------------
Total long-term debt due within
one year 75,336 20,753
------------------------------------------------------------
Preferred stock to be reacquired - 100,000
------------------------------------------------------------
Total $75,336 $120,753
============================================================
The annual first mortgage bond improvement fund requirement is 1 percent
of the aggregate principal amount of bonds of each series authenticated, so long
as a portion of that series is outstanding, and may be satisfied by the deposit
of cash and/or reacquired bonds, the certification of unfunded property
additions or a combination thereof. The 1998 requirement of $18.5 million was
satisfied by the deposit of cash in 1998, all of which was used for the
redemption of outstanding first mortgage bonds. Also in early 1998, the company
redeemed $5.9 million first mortgage bonds and retired $50 million first
mortgage bonds. Scheduled maturities amount to $991 thousand in connection with
capitalized office building leases and a street light lease.
12. NUCLEAR INSURANCE
Under the Price-Anderson Amendments Act of 1988 (Act), 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 Plant
Farley. The Act provides funds up to $8.9 billion for public liability claims
that could arise from a single nuclear incident. Plant Farley 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 which
could be assessed, after a nuclear incident, against all owners of nuclear
reactors. The company could be assessed up to $79 million per incident for each
licensed reactor it operates but not more than an aggregate of $10 million per
incident to be paid in a calendar year for each reactor. Such maximum
assessment, excluding any applicable state premium taxes, for the company is
$159 million per incident but not more than an aggregate of $20 million to be
paid for each incident in any one year.
The company is a member of Nuclear Electric Insurance Limited (NEIL), 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 per incident
is limited to $8 million under the current policy.
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 primary
coverage. This excess insurance is also provided by NEIL.
NEIL also covers the additional cost 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 cost of replacement power in an
amount up to $3.5 million per week (starting 17 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 per incident under current policies
for the company would be $10 million for excess property damage and $8 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.
II-81
NOTES (continued)
Alabama Power Company 1997 Annual Report
All retrospective assessments, whether generated for liability, property
or replacement power may be subject to applicable state premium taxes.
13. 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, 1997, retained earnings of $796 million were
restricted against the payment of cash dividends on common stock under terms of
the mortgage indenture.
14. QUARTERLY FINANCIAL INFORMATION
(Unaudited)
Summarized quarterly financial data for 1997 and 1996 are as follows:
Net Income
After
Dividends
Quarter Operating Operating on Preferred
Ended Revenues Income Stock
------------------- -----------------------------------------
(in thousands)
March 1997 $704,768 $123,455 $ 57,807
June 1997 728,089 125,750 63,137
September 1997 962,446 249,487 191,800
December 1997 753,808 128,511 63,195
March 1996 $732,809 $142,052 $ 73,159
June 1996 779,587 151,673 95,778
September 1996 913,308 222,523 152,589
December 1996 695,071 100,390 49,964
----------------------------------------------------------------
The company's business is influenced by seasonal weather conditions.
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II-84A
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II-86A
II-86B
II-86C
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II-88A
II-88B
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II-90A
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II-94B
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II-95
II-96
GEORGIA POWER COMPANY
FINANCIAL SECTION
II-97
MANAGEMENT'S REPORT
Georgia Power Company 1997 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 four
directors who are not employees, provides a broad overview of management's
financial reporting and control functions. At least three times a year this
committee meets with management, the internal auditors, and the independent
public accountants to ensure that these groups are fulfilling their obligations
and to discuss auditing, internal control and financial reporting matters. The
internal auditors and the independent public accountants have access to the
members of the audit committee at any time.
Management believes that its policies and procedures provide reasonable
assurance that the Company's operations are conducted with a high standard of
business ethics.
In management's opinion, the financial statements present fairly, in all
material respects, the financial position, results of operations and cash flows
of Georgia Power Company in conformity with generally accepted accounting
principles.
/s/H. Allen Franklin
H. Allen Franklin
President and Chief Executive Officer
/s/Warren Y. Jobe
Warren Y. Jobe
Executive Vice President, Treasurer and
Chief Financial Officer
February 11, 1998
II-98
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors
of Georgia Power Company:
We have audited the accompanying balance sheets and statements of capitalization
of Georgia Power Company (a Georgia corporation and a wholly owned subsidiary of
Southern Company) as of December 31, 1997 and 1996, 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, 1997. 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 11-108 through II-128)
referred to above present fairly, in all material respects, the financial
position of Georgia Power Company as of December 31, 1997 and 1996, and the
results of its operations and its cash flows for each of the three years in the
period ended December 31, 1997, in conformity with generally accepted
accounting principles.
/s/Arthur Andersen LLP
Atlanta, Georgia
February 11, 1998
II-99
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL
CONDITION
Georgia Power Company 1997 Annual Report
RESULTS OF OPERATIONS
Earnings
Georgia Power Company's 1997 earnings totaled $594 million, representing a $14
million (2.4 percent) increase over 1996. This earnings increase resulted
primarily from lower operating expenses, lower financing costs, and increased
non-operating income, partially offset by lower retail revenues and additional
depreciation charges pursuant to a Georgia Public Service Commission (GPSC)
retail accounting order discussed below. Earnings for 1996 totaled $580 million,
representing a $29 million (4.7 percent) decrease from 1995. Earnings for 1995
included an after-tax gain of approximately $12 million from the completion of
the sale of Plant Scherer Unit 4. The remaining decrease in 1996 earnings was
primarily due to increased operating and maintenance expenses, partially offset
by lower interest charges compared to the prior year.
Revenues
The following table summarizes the factors impacting operating revenues for the
1995-1997 period:
Increase (Decrease)
From Prior Year
-----------------------------------
1997 1996 1995
-----------------------------------
Retail - (in millions)
Sales growth $ 62 $ 58 $110
Weather (74) (25) 69
Fuel cost recovery (30) 28 66
Demand-side programs (3) (10) 36
------------------------------------------------------------------
Total retail (45) 51 281
------------------------------------------------------------------
Sales for resale -
Non-affiliates 1 (9) (61)
Affiliates 3 (41) 16
------------------------------------------------------------------
Total sales for resale 4 (50) (45)
------------------------------------------------------------------
Other operating revenues 10 10 7
------------------------------------------------------------------
Total operating revenues $ (31) $ 11 $243
==================================================================
Percent change (0.7)% 0.3% 5.8%
------------------------------------------------------------------
Retail revenues of $4 billion in 1997 decreased $45 million (1.1 percent)
from 1996 primarily due to milder-than-normal weather, as well as commercial and
industrial customers taking advantage of load management rates. Retail revenues
in 1996 increased $51 million (1.3 percent) over the prior year primarily due
to strong economic growth and an increase in sales to existing customers.
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.
Wholesale revenues from sales to non-affiliated utilities increased slightly
in 1997 and were as follows:
1997 1996 1995
-------------------------------
(in millions)
Outside service area -
Long-term contracts $ 71 $ 84 $ 98
Other sales 80 37 25
Inside service area 132 161 168
--------------------------------------------------------------
Total $283 $282 $291
==============================================================
Contractual long-term sales to Florida utilities for 1997 and 1996 are down
primarily due to scheduled reductions in the amount of capacity under those
contracts. See Note 7 to the financial statements for further information
regarding these sales. Revenues from other sales outside the service area
increased in 1997 and 1996 primarily due to power marketing activities.
Wholesale revenues from customers within the service area decreased in 1997 and
1996 primarily due to a decrease in revenues under a power supply agreement with
Oglethorpe Power Corporation (OPC) and, in 1996, recognition of a refund to
these customers. OPC decreased its purchases of capacity by 250 megawatts each
in September 1996 and 1997 and has notified the Company of its intent to
decrease purchases of capacity by an additional 250 megawatts in September 1998
and 1999.
Revenues from sales to affiliated companies within the Southern electric
system, as well as purchases of energy, will vary from year to year depending on
demand and the availability and cost of generating resources at each company.
These transactions do not have a significant impact on earnings.
II-100
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 1997 Annual Report
Kilowatt-hour (KWH) sales for 1997 and the percent change by year were as
follows:
Percent Change
---------------------------
1997
KWH 1997 1996 1995
------- -----------------------------
(in billions)
Residential 17.3 (3.0)% 3.0% 10.4%
Commercial 21.1 1.5 4.9 5.9
Industrial 26.7 1.9 3.6 3.9
Other 0.6 0.4 8.6 2.0
-------
Total retail 65.7 0.4 3.9 6.2
-------
Sales for resale -
Non-affiliates 6.8 (13.6) 19.4 (17.3)
Affiliates 1.7 44.6 (56.9) (10.4)
-------
Total sales for resale 8.5 (6.0) (3.0) (15.4)
-------
Total sales 74.2 (0.3) 3.0 2.8
=======
----------------------------------------------------------------
Residential sales declined 3.0 percent while sales to commercial and
industrial customers increased slightly by 1.5 percent and 1.9 percent,
respectively. Milder-than-normal temperatures experienced in 1997 contributed to
the moderate sales. Residential, commercial and industrial energy sales growth
in 1996 reflected strong economic growth and an increase in sales to existing
customers.
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:
1997 1996 1995
--------------------------
Total generation
(billions of kilowatt-hours) 66.5 63.7 64.3
Sources of generation
(percent) --
Coal 74.8 74.3 73.7
Nuclear 21.8 22.4 22.6
Hydro 2.7 2.7 3.0
Oil and gas 0.7 0.6 0.7
Average cost of fuel per net
kilowatt-hour generated
(cents) --
Coal 1.53 1.55 1.67
Nuclear 0.52 0.55 0.60
Oil and gas * * *
Total 1.32 1.35 1.44
--------------------------------------------------------------
* Not meaningful because of minimal generation from
fuel source.
Fuel expense increased 2.6 percent in 1997 primarily due to an increase in
generation, partially offset by a lower average cost of fuel. Fuel expense
decreased 7.3 percent in 1996 because of a decrease in generation resulting from
the timing of maintenance at nuclear plants and a lower average cost of fuel.
Purchased power expense decreased $66 million (17.1 percent) in 1997
primarily due to decreased purchases from affiliated companies and declines in
contractual capacity buyback purchases from the co-owners of Plant Vogtle.
Purchased power expense increased $72 million (22.8 percent) in 1996 primarily
due to increased purchases from affiliated companies as a result of the timing
of maintenance at nuclear plants discussed above. The increase in 1996 was
partially offset by a decrease in energy purchases from wholesale customers
within the service area and declines in the Plant Vogtle contractual capacity
buyback purchases. Under the terms of the 1991 GPSC retail rate order, the
II-101
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 1997 Annual Report
declines in the Plant Vogtle contractual capacity buyback purchases were
levelized over a six-year period ending September 1997. The levelization is
reflected in the amortization of deferred Plant Vogtle costs in the Statements
of Income. See Note 1 to the financial statements under "Plant Vogtle Phase-In
Plans" for additional information.
Other operation and maintenance (O&M) expenses, excluding the provision for
separation benefits, decreased 4.1 percent in 1997 primarily due to initiatives
in 1996 to reduce fossil generation materials inventory levels and an adjustment
in 1996 to deferred postretirement benefits to reflect changes in the retiree
benefits plan. Other O&M expenses increased 2.9 percent in 1996 primarily as a
result of the inventory initiatives and the adjustment to deferred
postretirement benefits discussed above, and increased costs under a three-year
retail accounting order effective January 1, 1996. See Note 3 to the financial
statements under "Retail Accounting Order" for additional information.
Depreciation and amortization increased $140 million in 1997 and $11 million
in 1996 primarily due to accelerated depreciation of generating plant pursuant
to the retail accounting order and an increase in plant-in-service.
The Company has deferred certain expenses and recorded a deferred return
related to Plant Vogtle under phase-in plans. The amortization of deferred Plant
Vogtle costs reflects the completion in September 1997 of the amortization of
the levelized buybacks and the Plant Vogtle Unit 1 cost deferrals under a 1987
GPSC order. See Note 1 to the financial statements under "Plant Vogtle Phase-In
Plans" for information regarding the deferral and subsequent amortization of
costs related to Plant Vogtle.
Other income increased in 1997 and decreased in 1996. The increase in 1997
is primarily due to increased tax benefits from losses of the parent company
allocated to the Company under the joint consolidated income tax agreement
between Southern Company and its subsidiaries. See Note 8 to the financial
statements for additional information. The decrease in 1996 is primarily due to
expenses in connection with the 1996 Summer Olympic games and the completion of
the sale in 1995 of Plant Scherer Unit 4, which resulted in an after-tax gain of
approximately $12 million.
Total financing costs decreased in 1997 and 1996. These changes were
primarily due to the refinancing or retirement of securities. The Company
refinanced or retired $701 million and $510 million of securities in 1997 and
1996, respectively. Interest and other charges increased $17 million
(6.8 percent) and decreased $52 million (17.4 percent) in 1997 and 1996,
respectively. While the issuance of additional mandatorily redeemable preferred
securities in August 1996, January 1997 and June 1997 increased interest and
other charges by $32 million and $6 million in 1997 and 1996, respectively,
dividends on preferred stock decreased $26 million and $3 million in 1997 and
1996, respectively.
Effects of Inflation
The Company is subject to rate regulation and income tax laws that are based on
the recovery of historical costs. Therefore, inflation creates an economic loss
because the Company is recovering its costs of investments in dollars that have
less purchasing power. While the inflation rate has been relatively low in
recent years, it continues to have an adverse effect on the Company because of
the large investment in long-lived utility plant. Conventional accounting for
historical cost does not recognize this economic loss nor the partially
offsetting gain that arises through financing facilities with fixed-money
obligations such as long-term debt and preferred stock. Any recognition of
inflation by regulatory authorities is reflected in the rate of return allowed.
Future Earnings Potential
The results of operations for the past three years are not necessarily
indicative of future earnings. The level of future earnings depends on numerous
factors including regulatory matters and energy sales.
The Company currently operates as a vertically integrated utility providing
electricity to customers within its traditional service area located in the
state of Georgia. Prices for electricity provided by the Company to retail
customers are set by the GPSC under cost-based regulatory principles.
On January 1, 1996, the Company began operating under a three-year retail
accounting order. Under the order, the Company's earnings are evaluated against
a retail return on common equity range of 10 percent to 12.5 percent. Earnings
II-102
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 1997 Annual Report
in excess of 12.5 percent will be used to accelerate the amortization of
regulatory assets or depreciation of electric plant. At its option, the Company
may also recognize accelerated amortization or depreciation of assets within the
allowed return on common equity range. The Company is required to absorb cost
increases of approximately $29 million annually during the order's three-year
operation, including $14 million annually of accelerated depreciation of
electric plant. During the order's operation, the Company will not file for a
general base rate increase unless its projected retail return on common equity
falls below 10 percent. Under the approved order, on July 1, 1998 the Company
will make a general rate case filing in response to which the GPSC would be
expected either to continue provisions of the accounting order or adopt
different ones. See Note 3 to the financial statements under "Retail Accounting
Order" for additional information.
Growth in energy sales is subject to a number of factors which traditionally
have included changes in contracts with neighboring utilities, energy
conservation practiced by customers, the elasticity of demand, weather,
competition, initiatives to increase sales to existing customers, and the rate
of economic growth in the Company's service area. Assuming normal weather,
retail sales growth is projected to be approximately 2 percent annually on
average during 1998 through 2000.
Beginning in September 1997, OPC decreased its purchases of capacity under a
power supply agreement by 250 megawatts and has notified the Company of its
intent to decrease purchases of capacity by an additional 250 megawatts each in
September 1998 and 1999. As a result, the Company's capacity revenues from OPC
will decline by approximately $26 million in 1998, an additional $25 million in
1999, and an additional $18 million in 2000. Under the amended 1995 Integrated
Resource Plan approved by the GPSC in March 1997, the resources associated with
the decreased purchases in 1997 and 1998 will be used to meet the needs of the
Company's retail customers through 2004.
The Company has entered into a 30-year purchase power agreement whereby the
Company will buy electricity from a 300 megawatt cogeneration facility, starting
in June 1998. Capacity and fixed O&M payments are projected to be $13 million in
1998, $14 million in 1999 and $14 million in 2000. The Company has also entered
into a five-year purchase power agreement scheduled to begin in June 2000 for
approximately 215 megawatts. Capacity and fixed O&M payments are estimated to be
approximately $7 million in 2000.
The amortization of Plant Vogtle costs deferred under phase-in plans will
decline by $89 million in 1998, $12 million in 1999, and $19 million in 2000.
These costs will be fully amortized by September 1999. See Note 1 to the
financial statements under "Plant Vogtle Phase-In Plans" for additional
information.
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.
As discussed in Note 3 to the financial statements, regulatory uncertainties
exist related to the Rocky Mountain pumped storage hydroelectric plant. On
January 14, 1998, the GPSC ordered that the Company be allowed approximately
$108 million of its $143 million investment in the plant in rate base as of
December 31, 1998. The Company has appealed the GPSC's order. If such order is
ultimately upheld, the Company will be required to record a charge to earnings
currently estimated at approximately $29 million, after taxes.
Southern Company and the Internal Revenue Service (IRS) have entered into a
settlement agreement that is subject to review and approval by the Joint
Congressional Committee on Taxation. If approved, the agreement would result in
a refund, including interest, to the Company. See Note 3 to the financial
statements under "Tax Litigation" for additional information.
Compliance costs related to current and future environmental laws and
regulations could affect earnings if such costs are not fully recovered. The
Clean Air Act and other important environmental items are discussed later under
"Environmental Issues."
The electric utility industry in the United States is currently undergoing a
period of dramatic change as a result of regulatory and competitive factors.
II-103
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 1997 Annual Report
Among the primary agents of change has been the Energy Policy Act of 1992
(Energy Act). The Energy Act allows independent power producers (IPPs) to access
a utility's transmission network in order to sell electricity to other
utilities. This enhances the incentive for IPPs to build cogeneration plants for
a utility's large industrial and commercial customers and sell electric energy
to other utilities. Also, electricity sales for resale rates are being driven
down by wholesale transmission access and numerous potential new energy
suppliers, including power marketers and brokers. The Company is aggressively
working to maintain and expand its share of wholesale sales in the Southeastern
power markets. Although the Energy Act does not permit retail customer access,
it was a major catalyst for the current restructuring and consolidation taking
place within the utility industry.
The Company continues to compete with other electric suppliers within the
state. In Georgia, most new retail customers with at least 900 kilowatts of
connected load may choose their electricity supplier. Numerous federal and state
initiatives are in varying stages to promote wholesale and retail competition
across the nation. Among other things, these initiatives allow customers to
choose their electricity provider. As these initiatives materialize, the
structure of the utility industry could radically change. Some states have
approved initiatives that result in a separation of the ownership and/or
operation of generating facilities from the ownership and/or operation of
transmission and distribution facilities. While the GPSC has held workshops to
discuss retail competition and industry restructuring, there has been no
proposed or enacted legislation to date in Georgia. Enactment would require
numerous issues to be resolved, including significant ones relating to
transmission pricing and recovery of costs. The ability of the Company to
recover all its costs, including the regulatory assets described in Note 1 to
the financial statements, could have a material effect on the financial
condition of the Company. The Company is attempting to reduce regulatory assets
and other costs through a three-year retail accounting order. See Note 3 to the
financial statements under "Retail Accounting Order" for additional information.
Unless the Company remains a low-cost producer and provides quality service,
the Company's retail energy sales growth could be limited as competition
increases. Conversely, continuing to be a low-cost producer could provide
opportunities to increase market share and profitability in markets that evolve
with changing regulation.
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 that are not specifically recoverable, and
determine if any other assets have been impaired. See Note 1 to the financial
statements under "Regulatory Assets and Liabilities" for additional information.
The staff of the Securities and Exchange Commission has questioned certain
of the current accounting practices of the electric utility industry - including
the Company's - regarding the recognition, measurement, and classification of
decommissioning costs for nuclear generating facilities in the financial
statements. In response to these questions, the FASB has decided to review the
accounting for liabilities related to closure and removal of long-lived assets,
including nuclear decommissioning. If the FASB issues new accounting rules, the
estimated costs of closing and removing the Company's nuclear and other
facilities may be required to be recorded as liabilities in the Balance Sheets.
Also, the annual provisions for such costs could change. Because of the
Company's current ability to recover closure and removal costs through rates,
these changes would not have a significant adverse effect on results of
operations. See Note 1 to the financial statements under "Depreciation and
Nuclear Decommissioning" for additional information.
The Company is heavily dependent upon complex computer systems for all
phases of its operations. The year 2000 issue -- common to most corporations --
concerns the inability of certain software and databases to properly recognize
date sensitive information related to the year 2000 and thereafter. This problem
could result in a material disruption to the Company's operations, if not
corrected. The Company has assessed and developed a detailed strategy to prevent
or at least minimize problems related to the year 2000 issue. In 1997 resources
were committed and implementation began to modify the affected information
systems. Total costs related to the project are estimated to be approximately
$33 million, of which $3 million was spent in 1997. The remaining costs will be
II-104
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 1997 Annual Report
expensed primarily in 1998. Implementation is currently on schedule. Although
the degree of success of this project cannot be determined at this time,
management believes there will be no significant effect on the Company's
operations.
Exposure to Market Risks
Due to cost-based rate regulation, the Company has limited exposure to market
volatility in interest rates and prices of electricity. To mitigate residual
risks relative to movements in electricity prices, the Company enters into fixed
price contracts for the purchase and sale of electricity through the wholesale
electricity market. Realized gains and losses are recognized in the income
statement as incurred. At December 31, 1997, exposure from these activities was
not material to the Company's financial position, results of operations, or cash
flows.
New Accounting Standards
The FASB has issued Statement No. 130, Reporting Comprehensive Income, which
will be effective in 1998. This statement establishes standards for reporting
and display of comprehensive income and its components in a full set of general
purpose financial statements. The objective of the statement is to report a
measure of all changes in equity of an enterprise that result from transactions
and other economic events of the period other than transactions with owners
(comprehensive income). Comprehensive income is the total of net income and all
other nonowner changes in equity. The Company will adopt this statement in 1998.
The FASB has issued Statement No. 131, Disclosure about Segments of an
Enterprise and Related Information. This statement requires that a public
business enterprise report financial and descriptive information about its
reportable operating segments. Generally, financial information is required to
be reported on the basis that it is used by the chief operating decision maker
in deciding how to allocate resources and in assessing performance. This
statement also establishes standards for related disclosures about products and
services, geographic areas, and major customers. The Company adopted the new
rules in 1997, and they did not have a significant impact on the Company's
financial reporting. However, this conclusion may change as industry
restructuring and competitive factors influence the company's operations.
FINANCIAL CONDITION
Plant Additions
In 1997 gross utility plant additions were $476 million. These additions were
primarily related to transmission and distribution facilities and to the
purchase of nuclear fuel. The funds needed for gross property additions are
currently provided from operations. The Statements of Cash Flows provide
additional details.
Financing Activities
In 1997, the Company continued to lower its financing costs by refinancing
higher-cost issues. New issues during 1995 through 1997 totaled $1.6 billion and
retirement or repayment of securities totaled $2.2 billion. The retirements
included the redemption of $131 million in 1995 of first mortgage bonds with the
proceeds from the Plant Scherer Unit 4 sales. Composite financing rates for
long-term debt and preferred stock for the years 1995 through 1997, as of
year-end, were as follows:
1997 1996 1995
---------------------------------
Composite interest rate
on long-term debt 6.11% 6.39% 6.57%
Composite preferred
stock dividend rate 5.18 6.34 6.73
----------------------------------------------------------------
The Company's current securities ratings are as follows:
Duff & Standard &
Phelps Moody's Poor's
------------------------------------
First Mortgage Bonds AA- A1 A+
Preferred Stock A+ a2 A
Unsecured Bonds A+ A2 A
Commercial Paper D1+ P1 A1
-----------------------------------------------------------------
Subsidiaries of the Company have issued mandatorily redeemable preferred
securities. See Note 9 to the financial statements under "Preferred Securities"
for additional information.
In January 1998, the Company issued $145 million of 6 7/8% unsecured senior
notes due December 31, 2047. The senior notes are subordinated to all secured
II-105
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 1997 Annual Report
debt of the Company, including its first mortgage bonds.
Liquidity and Capital Requirements
Cash provided from operations decreased by $15 million in 1997, primarily due to
lower retail revenues.
The Company estimates that construction expenditures for the years 1998
through 2000 will total $506 million, $561 million and $549 million,
respectively. Investments in transmission and distribution facilities,
enhancements to existing generating plants, and equipment to comply with the
provisions of the Clean Air Act are planned.
Cash requirements for improvement fund requirements, redemptions announced,
and maturities of long-term debt and preferred stock are expected to total $693
million during 1998 through 2000.
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 1998 through 2000, the amount to be funded totals $24
million annually. For additional information concerning nuclear decommissioning
costs, see Note 1 to the financial statements under "Depreciation and Nuclear
Decommissioning."
Sources of Capital
The Company expects to meet future capital requirements primarily using funds
generated from operations and, if needed, by the issuance of new debt and equity
securities, term loans, and short-term borrowings. To meet short-term cash needs
and contingencies, the Company had approximately $1.3 billion of unused credit
arrangements with banks at the beginning of 1998. See Note 9 to the financial
statements under "Bank Credit Arrangements" for additional information.
The Company historically has relied on issuances of first mortgage bonds and
preferred stock, in addition to pollution control revenue bonds issued for its
benefit by public authorities, to meet its long-term external financing
requirements. Recently, the Company's financings have consisted of unsecured
debt and trust preferred securities. In this regard, the Company sought and
obtained stockholder approval in 1997 to amend its corporate charter eliminating
restrictions on the amounts of unsecured indebtedness it may incur.
If the Company chooses to issue first mortgage bonds or preferred stock, it
is required to meet certain coverage requirements specified in its mortgage
indenture and corporate charter. 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 -- significantly
impacted the operating companies of Southern Company, including Georgia Power.
Specific reductions in sulfur dioxide and nitrogen oxide emissions from
fossil-fired generating plants are required in two phases. Phase I compliance
began in 1995 and initially affected 28 generating units in the Southern
electric system. As a result of Southern Company's compliance strategy, an
additional 22 generating units were brought into compliance with Phase I
requirements. Phase II compliance is required in 2000, and all fossil-fired
generating plants in the Southern electric system will be affected.
Southern Company achieved Phase I sulfur dioxide compliance at the affected
units by switching to low-sulfur coal, which required some equipment upgrades.
Construction expenditures for Georgia Power's Phase I compliance totaled
approximately $167 million.
For Phase II sulfur dioxide compliance, Southern Company could use emission
allowances, increase fuel switching, and/or install flue gas desulfurization
equipment at selected plants. Also, equipment to control nitrogen oxide
emissions will be installed on additional system fossil-fired units as required
to meet Phase II limits and ozone nonattainment requirements for metropolitan
Atlanta through 2000. Current compliance strategy for Phase II and ozone
nonattainment could require total estimated construction expenditures of
approximately $39 million, of which $28 million remains to be spent as of
December 31, 1997.
A significant portion of costs related to the acid rain provision of the
Clean Air Act is expected to be recovered through existing ratemaking
II-106
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 1997 Annual Report
provisions. However, there can be no assurance that all Clean Air Act costs will
be recovered.
In July 1997, the Environmental Protection Agency (EPA) revised the national
ambient air quality standards for ozone and particulate matter. This revision
makes the standards significantly more stringent. Also, in October 1997, the EPA
issued a proposed regional ozone rule that --if implemented--could require
substantial further reductions in NOx emissions from fossil-fueled generating
facilities. Implementation of the standards and the proposed rule could result
in significant additional compliance costs and capital expenditures that cannot
be determined at this time.
The EPA and state environmental regulatory agencies are reviewing and
evaluating various matters including: emission control strategies for ozone
nonattainment areas; additional controls for hazardous air pollutant emissions;
and hazardous waste disposal requirements. The impact of new standards will
depend on the development and implementation of applicable regulations.
The Company must comply with other environmental laws and regulations that
cover the handling and disposal of hazardous waste. Under these various laws and
regulations, the Company could incur costs to clean up properties currently or
previously owned. The Company conducts studies to determine the extent of any
required clean-up costs and has recognized in the financial statements costs to
clean up known sites. These costs for the Company amounted to $4 million, $2
million and $8 million, in 1997, 1996, and 1995, respectively. Additional sites
may require environmental remediation for which the Company may be liable for a
portion of or all required clean-up costs. See Note 3 to the financial
statements under "Certain Environmental Contingencies" for information regarding
the Company's potentially responsible party status at a site in Brunswick,
Georgia, and the status of sites listed on the State of Georgia's hazardous site
inventory.
Several major pieces of environmental legislation are being considered for
reauthorization or amendment by Congress. These include: the Clean Air Act; the
Clean Water Act; the Comprehensive Environmental Response, Compensation, and
Liability Act; the Resource Conservation and Recovery Act; the Toxic Substances
Control Act; and the Endangered Species Act. Changes to these laws could affect
many areas of the Company's operations. The full impact of any such changes
cannot be determined at this time.
Compliance with possible additional legislation related to global climate
change, electromagnetic fields and other environmental and health concerns could
significantly affect the Company. The impact of new legislation -- if any --
will depend on the subsequent development and implementation of applicable
regulations. In addition, the potential exists for liability as the result of
lawsuits alleging damages caused by electromagnetic fields.
Cautionary Statement Regarding Forward-Looking Information
The Company's 1997 Annual Report contains forward-looking statements in addition
to historical information. The Company cautions that there are various important
factors that could cause actual results to differ materially from those
indicated in the forward-looking statements; accordingly, there can be no
assurance that such indicated results will be realized. These factors include
legislative and regulatory initiatives regarding deregulation and restructuring
of the electric utility industry; the extent and timing of the entry of
additional competition in the Company's markets; potential business strategies
-- including acquisitions or dispositions of assets or internal restructuring --
that may be pursued by Southern Company; state and federal rate regulation;
changes in or application of environmental and other laws and regulations to
which the Company is subject; political, legal and economic conditions and
developments; financial market conditions and the results of financing efforts;
changes in commodity prices and interest rates; weather and other natural
phenomena; and other factors discussed in the reports--including Form
10-K--filed from time to time by the Company with the Securities and Exchange
Commission.
II-107
II-108
II-109
II-110
II-111
II-112
II-113
NOTES TO FINANCIAL STATEMENTS
Georgia Power Company 1997 Annual Report
1. SUMMARY OF SIGNIFICANT ACCOUNTING
POLICIES
General
The Company is a wholly owned subsidiary of Southern Company, which is the
parent company of five operating companies, Southern Company Services (SCS), a
system service company, Southern Communications Services (Southern
Communications), Southern Energy, Inc. (Southern Energy), Southern Nuclear
Operating Company (Southern Nuclear), Southern Company Energy Solutions, and
other direct and indirect subsidiaries. The operating companies (Alabama Power
Company, Georgia Power Company, Gulf Power Company, Mississippi Power Company,
and Savannah Electric and Power Company) provide electric service in four
Southeastern states. Contracts among the operating companies -- dealing with
jointly owned generating facilities, interconnecting transmission lines, and the
exchange of electric power -- are regulated by the Federal Energy Regulatory
Commission (FERC) or the Securities and Exchange Commission (SEC). SCS provides,
at cost, specialized services to Southern Company and subsidiary companies.
Southern Communications provides digital wireless communications services to the
operating companies and also markets these services to the public within the
Southeast. Southern Energy designs, builds, owns, and operates power production
and delivery facilities and provides a broad range of energy related services in
the United States and international markets. Southern Nuclear provides services
to Southern Company's nuclear power plants. Southern Company Energy Solutions
develops new business opportunities related to energy products and services.
Southern Company is registered as a holding company under the Public Utility
Holding Company Act of 1935 (PUHCA). Both Southern Company and its subsidiaries
are subject to the regulatory provisions of this act. The Company is also
subject to regulation by the FERC and the Georgia Public Service Commission
(GPSC). The Company follows generally accepted accounting principles (GAAP) and
complies with the accounting policies and practices prescribed by the respective
regulatory commissions. The preparation of financial statements in conformity
with GAAP requires the use of estimates, and the actual results may differ from
these estimates.
Certain prior years' data presented in the financial statements have been
reclassified to conform with current year presentation.
Regulatory Assets and Liabilities
The Company is subject to the provisions of Financial Accounting Standards Board
(FASB) Statement No. 71, Accounting for the Effects of Certain Types of
Regulation. Regulatory assets represent probable future revenues to the Company
associated with certain costs that are expected to be recovered from customers
through the ratemaking process. Regulatory liabilities represent probable future
reductions in revenues associated with amounts that are expected 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:
1997 1996
---------- ---------
(in millions)
--------------------
Deferred income taxes $ 688 $ 754
Deferred income tax credits (298) (318)
Premium on reacquired debt 167 167
Corporate building lease 52 51
Deferred Plant Vogtle costs 50 171
Vacation pay 41 40
Postretirement benefits 38 38
Department of Energy assessments 29 32
Deferred nuclear outage costs 28 18
Demand-side program costs 11 44
Other, net 10 (9)
--------------------------------------------------------------
Total $ 816 $ 988
==============================================================
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 net regulatory assets and liabilities that are not specifically
recoverable through regulated rates. In addition, the Company would be required
to determine if any impairment to other assets exists, including plant, and
write down the assets, if impaired, to their fair value.
II-114
NOTES (continued)
Georgia Power Company 1997 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, and certain other costs.
Revenues are adjusted for differences between recoverable fuel costs and amounts
actually recovered in current rates.
The Company has a diversified base of customers. No single customer or
industry comprises 10 percent or more of revenues. In 1997, 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 $76
million in 1997, $78 million in 1996, and $86 million in 1995. The Company has a
contract with the U.S. Department of Energy (DOE) that provides for the
permanent disposal of spent nuclear fuel, which was scheduled to begin in 1998.
However, the actual year this service will begin is uncertain. Sufficient
storage capacity currently is available to permit operation into 2003 at Plant
Hatch and into 2008 at Plant Vogtle. Activities for adding dry cask storage
capacity at Plant Hatch by as early as 1999 are in progress.
Also, the Energy Policy Act of 1992 required the establishment in 1993 of a
Uranium Enrichment Decontamination and Decommissioning Fund, which is to be
funded in part by a special assessment on utilities with nuclear plants. This
fund will be used by the DOE for the decontamination and decommissioning of its
nuclear fuel enrichment facilities. The assessment will be paid over a 15-year
period, which began in 1993. The law provides that utilities will recover these
payments in the same manner as any other fuel expense. The Company -- based on
its ownership interests -- estimates its remaining liability under this law at
December 31, 1997, to be approximately $27 million. This obligation is recorded
in the accompanying Balance Sheets.
Depreciation and Nuclear Decommissioning
Depreciation of the original cost of depreciable utility plant in service is
provided primarily by using composite straight-line rates, which approximated
3.1 percent in 1997 and 1996 and 3.2 percent in 1995. In addition, the Company
recorded accelerated depreciation of electric plant of $159 million in 1997, $24
million in 1996, and $6 million in 1995. The amount of such charges in the
accumulated provision for depreciation is $189 million at December 31, 1997. See
Note 3 under "Retail Accounting Order" for additional information. When property
subject to depreciation is retired or otherwise disposed of in the normal course
of business, its cost -- together with the cost of removal, less salvage -- is
charged to the accumulated provision for depreciation. Minor items of property
included in the original cost of the plant are retired when the related property
unit is retired. Depreciation expense includes an amount for the expected costs
of decommissioning nuclear facilities and removal of other facilities.
In 1988, the Nuclear Regulatory Commission (NRC) adopted regulations
requiring all licensees operating commercial nuclear power reactors to establish
a plan for providing, with reasonable assurance, funds for decommissioning. The
Company has established external trust funds to comply with the NRC's
regulations. Amounts previously recorded in internal reserves are being
transferred into the external trust funds over a set period of time as ordered
by the GPSC. Earnings on the trust funds are considered in determining
decommissioning expense. The NRC's minimum external funding requirements are
based on a generic estimate of the cost to decommission the radioactive portions
of a nuclear unit based on the size and type of reactor. The Company has filed
plans with the NRC to ensure that -- over time -- the deposits and earnings of
the external trust funds will provide the minimum funding amounts prescribed by
the NRC.
Site study cost is the estimate to decommission the facility as of the site
study year, and ultimate cost is the estimate to decommission the facility as of
II-115
NOTES (continued)
Georgia Power Company 1997 Annual Report
the retirement date. The estimated costs of decommissioning -- both site study
costs and ultimate costs at December 31, 1997 -- based on the Company's
ownership interests -- were as follows:
Plant Plant
Hatch Vogtle
--------------------
Site study basis (year) 1997 1997
Decommissioning periods:
Beginning year 2014 2027
Completion year 2027 2038
------------------------------------------------------------
(in millions)
Site study costs:
Radiated structures $372 $317
Non-radiated structures 33 44
------------------------------------------------------------
Total $405 $361
============================================================
(in millions)
Ultimate costs:
Radiated structures $722 $922
Non-radiated structures 65 129
------------------------------------------------------------
Total $787 $1,051
============================================================
(in millions)
Amount expensed in 1997 $ 11 $ 9
Accumulated provisions:
Balance in external trust funds $118 $ 76
Balance in internal reserves 23 13
------------------------------------------------------------
Total $141 $ 89
============================================================
Significant assumptions:
Inflation rate 3.6% 3.6%
Trust earnings rate 6.5 6.5
------------------------------------------------------------
Annual provisions for nuclear decommissioning are based on an annuity method
as approved by the GPSC. The decommissioning costs currently included in cost of
service are $320 million and $267 million for plants Hatch and Vogtle,
respectively. These amounts are based on the higher of the costs to
decommission the radioactive portions of the plants based on 1994 site studies
or the 1993 NRC minimum funding requirements. The estimated ultimate costs
associated with the amounts currently included in cost of service are $781
million and $1.1 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 the assumed date of
decommissioning, changes in NRC requirements, changes in the assumptions used in
making estimates, changes in regulatory requirements, changes in technology, and
changes in costs of labor, materials, and equipment.
Income Taxes
The Company uses the liability method of accounting for deferred income taxes
and provides deferred income taxes for all significant income tax temporary
differences. Investment tax credits utilized are deferred and amortized to
income over the average lives of the related property.
Plant Vogtle Phase-In Plans
In 1987 and 1989, the GPSC ordered that the allowed costs of Plant Vogtle, a
two-unit nuclear facility of which Georgia Power owns 45.7 percent, be phased
into rates. Pursuant to the orders, the Company recorded a deferred return under
phase-in plans until October 1991 when the allowed investment was fully
reflected in rates. In 1991, the GPSC levelized the remaining Plant Vogtle
declining capacity buyback expenses over a six-year period. In addition, the
Company deferred certain Plant Vogtle operating expenses and financing costs
under accounting orders issued by the GPSC. These GPSC orders provide for the
recovery of deferred costs within 10 years. Costs deferred under the 1987 order
and the levelized buybacks were fully recovered as of September 1997.
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 1997, 1996 and 1995, the average AFUDC rates
were 7.60 percent, 6.59 percent and 6.53 percent, respectively. AFUDC, net of
taxes, as a percentage of net income after dividends on preferred stock, was
less than 2.0 percent for 1997, 1996, and 1995.
II-116
NOTES (continued)
Georgia Power Company 1997 Annual Report
Utility Plant
Utility plant is stated at original cost with the exception of Plant Vogtle,
which is stated at cost less regulatory disallowances. Original cost includes:
materials; labor; payroll-related costs such as taxes, pensions, and other
benefits; and the cost of funds used during construction. The cost of
maintenance, repairs, and replacement of minor items of property is charged to
maintenance expense. The cost of replacements of property (exclusive of minor
items of property) is charged to utility plant.
Cash and Cash Equivalents
For purposes of the Statements of Cash Flows, temporary cash investments are
considered cash equivalents. Temporary cash investments are securities with
original maturities of 90 days or less.
Financial Instruments
The Company's financial instruments for which the carrying amounts did not
approximate fair value at December 31 were as follows:
Carrying Fair
Amount Value
------------------------
Long-term debt: (in millions)
At December 31, 1997 $3,125 $3,170
At December 31, 1996 3,174 3,206
Preferred securities:
At December 31, 1997 689 720
At December 31, 1996 325 333
--------------------------------------------------------------
The fair values for securities were based on either closing market prices or
closing prices of comparable instruments.
Materials and Supplies
Generally, materials and supplies include the cost of transmission, distribution
and generating plant materials. Materials are charged to inventory when
purchased and then expensed or capitalized to plant, as appropriate, when
installed.
2. RETIREMENT BENEFITS
Pension Plan
The Company has a defined benefit, trusteed,
non-contributory pension plan covering substantially all regular employees.
Benefits are based on one of the following formulas: years of service and final
average pay or years of service and a flat-dollar benefit. The Company uses the
"entry age normal method with a frozen initial liability" actuarial method for
funding purposes, subject to limitations under federal income tax regulations.
Amounts funded to the pension trusts are primarily invested in equity and
fixed-income securities. FASB Statement No. 87, Employers' Accounting for
Pensions, requires use of the "projected unit credit" actuarial method for
financial reporting purposes.
Postretirement Benefits
The Company also provides certain medical care and life insurance benefits for
retired employees. Substantially all employees may become eligible for these
benefits when they retire. Qualified trusts are funded to the extent deductible
under federal income tax regulations and to the extent required by the GPSC and
the FERC. During 1997 and 1996, the Company funded $24 million and $25 million,
respectively, to the qualified trusts. Amounts funded are primarily invested in
debt and equity securities.
FASB Statement No. 106, Employers' Accounting for Postretirement Benefits
Other Than Pensions, requires that medical care and life insurance benefits for
retired employees be accounted for on an accrual basis using a specified
actuarial method, "benefit/years-of-service." In October 1993, the GPSC ordered
the Company to phase in the adoption of Statement No. 106 to cost of service
over a five-year period, whereby one-fifth of the additional cost was expensed
in 1993, and the remaining additional costs were deferred. An additional
one-fifth of the costs were expensed each succeeding year until the costs were
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.
II-117
NOTES (continued)
Georgia Power Company 1997 Annual Report
Funded Status and Cost of Benefits
The funded status of the plans and reconciliation to amounts reflected in the
Balance Sheets at December 31 are as follows:
Pension
---------------------
1997 1996
---------------------
(in millions)
---------------------
Actuarial present value of
benefit obligations:
Vested benefits $ 841 $ 806
Non-vested benefits 29 52
----------------------------------------------------------------
Accumulated benefit obligation 870 858
Additional amounts related
to projected salary increases 249 314
---------------------------------------------------------------
Projected benefit obligation 1,119 1,172
Less:
Fair value of plan assets 1,931 1,797
Unrecognized net gain (753) (591)
Unrecognized prior service cost 48 56
Unrecognized transition asset (39) (47)
---------------------------------------------------------------
Prepaid asset recognized in
the Balance Sheets $ 68 $ 43
===============================================================
Postretirement
Benefits
---------------------
1997 1996
---------------------
(in millions)
Actuarial present value of
benefit obligation:
Retirees and dependents $246 $217
Employees eligible to retire 33 29
Other employees 156 184
---------------------------------------------------------------
Accumulated benefit obligation 435 430
Less:
Fair value of plan assets 151 112
Unrecognized net loss 47 50
Unrecognized transition
obligation 139 157
---------------------------------------------------------------
Accrued liability recognized in the
Balance Sheets $ 98 $111
===============================================================
The weighted average rates used in actuarial calculations were:
1997 1996 1995
----------------------------
Discount 7.5% 7.8% 7.3%
Annual salary increase 5.0 5.3 4.8
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 8.8 percent for 1997, decreasing gradually to 5.5 percent through the year
2005 and remaining at that level thereafter. An annual increase in the assumed
medical care cost trend rate of 1 percent would increase the accumulated benefit
obligation as of December 31, 1997, by $43 million and the aggregate of the
service and interest cost components of the net postretirement cost by $4
million.
The components of the plans' net costs are shown below:
Pension
----------------------------
1997 1996 1995
----------------------------
(in millions)
Benefits earned during the year $ 30 $ 35 $ 33
Interest cost on projected
benefit obligation 82 86 78
Actual return on plan assets (301) (202) (317)
Net amortization 161 62 185
-----------------------------------------------------------------
Net pension benefit $ (28) $ (19) $ (21)
=================================================================
Of net pension amounts recorded, $20 million in 1997, $14 million in 1996,
and $15 million in 1995 were recorded as a reduction to operating expense, and
the remainder was recorded as a reduction to construction and other accounts.
II-118
NOTES (continued)
Georgia Power Company 1997 Annual Report
Postretirement Benefits
-------------------------
1997 1996 1995
-------------------------
(in millions)
Benefits earned during the year $ 7 $ 9 $13
Interest cost on accumulated
benefit obligation 32 30 34
Amortization of transition
obligation 9 9 16
Actual return on plan assets (8) (6) (8)
Net amortization 2 3 4
---------------------------------------------------------------
Net postretirement cost $42 $45 $59
===============================================================
Of the above net postretirement benefit costs recorded, $32 million in 1997,
$29 million in 1996, and $33 million in 1995 were charged to operating expenses.
In addition, $3 million in 1996 and $11 million in 1995 were deferred, and the
remainder was charged to construction and other accounts. During 1996, the
Company expensed an additional $19 million due to an adjustment to amounts
previously deferred under the GPSC order as a result of changes in the
postretirement benefit plan.
Work Force Reduction Programs
The Company has incurred costs for work force reduction programs. The costs
related to these programs were $5 million in 1997, $39 million in 1996 and $11
million in 1995. Additionally, the Company recognized $4 million in 1997, $9
million in 1996, and $3 million in 1995 for its share of costs associated with
SCS's work force reduction programs.
3. REGULATORY AND LITIGATION MATTERS
Retail Accounting Order
On February 16, 1996, the GPSC approved a three-year accounting order for the
Company. Under the order, effective January 1, 1996, the Company's earnings are
evaluated against a retail return on common equity range of 10 percent to 12.5
percent. Earnings in excess of 12.5 percent will be used to accelerate the
amortization of regulatory assets or depreciation of electric plant. At its
option, the Company may also recognize accelerated amortization or depreciation
of assets within the allowed return on common equity range. The Company is
required to absorb cost increases of approximately $29 million annually during
the order's three-year operation, including $14 million annually of accelerated
depreciation of electric plant. During the order's operation, the Company will
not file for a general base rate increase unless its projected retail return on
common equity falls below 10 percent. Under the approved order, on July 1, 1998,
the Company will make a general rate case filing in response to which the GPSC
would be expected either to continue the provisions of the accounting order or
adopt different ones.
The Company's 1996 retail return on common equity was within the 10 percent
to 12.5 percent range. During 1997, for earnings in excess of the 12.5% retail
return, the Company recorded charges of $135 million that are presented in the
financial statements as depreciation expense of electric plant and as an
addition to the reserve for depreciation.
In November 1996, on appeal by a consumer group, the Superior Court of
Fulton County, Georgia, reversed the GPSC's accounting order and remanded the
matter to the GPSC. The Court found that statutory requirements applicable to
rate cases should have been, but were not, followed. The GPSC and the Company
subsequently appealed the Superior Court's decision. In October 1997, the Court
of Appeals upheld the accounting order. No appeal of that decision was filed
within the allowable time frame. The order stands as written, and this matter is
now concluded.
FERC Review of Equity Returns
In May 1991, the FERC ordered that hearings be conducted concerning the
reasonableness of the Southern electric system's wholesale rate schedules and
contracts that have a return on common equity of 13.75 percent or greater. The
contracts that could be affected by the hearings include substantially all of
the transmission, unit power, long-term power, and other similar contracts.
In August 1992, a FERC administrative law judge issued an opinion that
changes in rate schedules and contracts were not necessary and that the FERC
staff failed to show how any changes were in the public interest. The FERC staff
has filed exceptions to the administrative law judge's opinion, and the matter
remains pending before the FERC.
In August 1994, the FERC instituted another proceeding based on
substantially the same issues as in the 1991 proceeding. In November 1995, a
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NOTES (continued)
Georgia Power Company 1997 Annual Report
FERC administrative law judge issued an opinion that the FERC staff failed to
meet its burden of proof, and therefore no change in the equity return was
necessary. The FERC staff has filed exceptions to the administrative law judge's
opinion, and the matter remains pending before the FERC.
If the rates of return on common equity recommended by the FERC staff were
applied to all the schedules and contracts involved in both proceedings, as well
as certain other contracts that reference these proceedings in determining
return on common equity and if refunds were ordered, the amount of refunds could
range up to approximately $71 million at December 31, 1997. Although management
believes that rates are not excessive and that refunds are not justified, the
final outcome of this matter cannot now be determined.
Rocky Mountain Plant Status
In its 1985 financing order, the GPSC concluded that completion of the Rocky
Mountain pumped storage hydroelectric plant in 1991, as then planned, was not
economically justifiable and reasonable and withheld authorization for the
Company to spend funds from approved securities issuances on that plant. In
1988, the Company and Oglethorpe Power Corporation (OPC) entered into a joint
ownership agreement for OPC to assume responsibility for the construction and
operation of the plant, as discussed in Note 6. In 1995, the plant went into
commercial operation.
In June 1996, the GPSC initiated a review of the plant. On January 14, 1998,
the GPSC ordered that the Company be allowed approximately $108 million of its
$143 million investment in the plant in rate base as of December 31, 1998. The
Company has appealed the GPSC's order to the Superior Court of Fulton County,
Georgia. If such order is ultimately upheld, the Company will be required to
record a charge to earnings currently estimated at approximately $29 million,
after taxes. The final outcome of this matter cannot now be determined.
Accordingly, no provision related to the GPSC's disallowance has been recorded.
Tax Litigation
In August 1997, Southern Company and the Internal Revenue Service (IRS) entered
into a settlement agreement related to tax issues for the years 1984 through
1987. The agreement is subject to the review and approval by the Joint
Congressional Committee on Taxation. If approved by the Joint Committee, the
agreement would resolve all issues in the case for the years before the U. S.
Tax Court, resulting in a refund to the Company of approximately $140 million.
This amount includes interest of $61 million. The tax litigation was related to
a timing issue as to when taxes should have been paid; therefore, only the
interest portion will affect future income. There can be no assurance that such
Joint Committee approval will be received.
Demand-Side Conservation Programs
In August 1995, the GPSC ordered the Company to discontinue its current
demand-side conservation programs by the end of 1995. Rate riders previously
approved by the GPSC for recovery of the Company's costs incurred in connection
with these programs remained in effect until January 1998 when costs deferred
were fully collected.
Under the Retail Accounting Order approved February 16, 1996, the Company
will recognize approximately $29 million of deferred program costs over a
three-year period which will not be recovered through the riders.
Certain Environmental Contingencies
In January 1995, the Company and four other unrelated entities were notified by
the EPA that they have been designated as potentially responsible parties under
the Comprehensive Environmental Response, Compensation and Liability Act with
respect to a site in Brunswick, Georgia. As of December 31, 1997, the Company
has recognized approximately $5 million in expenses associated with this site.
This represents the Company's agreed upon share of removal and remedial
investigation and feasibility study costs. The final outcome of this matter
cannot now be determined. However, based on the nature and extent of the
Company's activities relating to the site, management believes that the
Company's portion of any remaining remediation costs should not be material.
In compliance with the Georgia Hazardous Site Response Act of 1993, the
State of Georgia was required to compile an inventory of all known or suspected
sites where hazardous wastes, constituents or substances have been disposed of
or released in quantities deemed reportable by the State. In developing this
II-120
NOTES (continued)
Georgia Power Company 1997 Annual Report
list, the State identified several hundred properties throughout the State,
including 25 sites which may require environmental remediation that were either
previously or are currently owned by the Company. The majority of these sites
are electrical power substations and power generation facilities. The Company
has remediated nine electrical substations on the list at a cost of
approximately $3 million. In addition, the Company has recognized approximately
$17 million in expenses through December 31, 1997 for the assessment of the
remaining sites on the list and the anticipated clean-up cost for 11 sites that
the Company plans to remediate. Any cost of remediating the remaining sites
cannot presently be determined until such studies are completed for each site
and the State of Georgia determines whether remediation is required. If all
listed sites were required to be remediated, the Company could incur expenses of
up to approximately $15 million in additional clean-up costs and construction
expenditures of up to approximately $65 million to develop new waste management
facilities or install additional pollution control devices.
The accrued costs for environmental remediation obligations are not
discounted to their present value.
New Wholesale Agreement
On January 10, 1997, the Company and the Municipal Electric Authority of Georgia
(MEAG) reached an agreement to enter into a new power supply relationship which
would replace the partial requirements tariff pursuant to which the Company
sells wholesale energy to MEAG and the scheduling services agreement between the
Company and MEAG. The new power supply contract was approved by FERC and was
implemented in August 1997.
Nuclear Performance Standards
In October 1989, the GPSC adopted a nuclear performance standard for the
Company's nuclear generating units under which the performance of plants Hatch
and Vogtle will be evaluated every three years. The performance standard is
based on each unit's capacity factor as compared to the average of all
comparable U.S. nuclear units operating at a capacity factor of 50 percent or
higher during the three-year period of evaluation. Depending on the performance
of the units, the Company could receive a monetary reward or penalty under the
performance standards criteria.
The first evaluation was conducted in 1993 for performance during the
1990-92 period. The GPSC approved a performance reward of approximately $8.5
million for the Company. This reward was collected through the retail fuel cost
recovery provision and recognized in income over a 36-month period which ended
in October 1996. In January 1997, the GPSC approved a performance award of
approximately $11.7 million for performance during the 1993-95 period. This
reward is being collected through the retail fuel cost recovery provision and
recognized in income over a 36-month period that began in January 1997.
4. COMMITMENTS
Construction Program
While the Company has no traditional baseload generating plants under
construction, the construction of one jointly owned combustion turbine peaking
unit was completed in January 1997. In addition, significant construction of
transmission and distribution facilities, and projects to upgrade and extend the
useful life of generating plants will continue. The Company currently estimates
property additions to be approximately $506 million in 1998, $561 million in
1999, and $549 million in 2000. The estimates for property additions for the
three-year period include $28 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.
II-121
NOTES (continued)
Georgia Power Company 1997 Annual Report
Total estimated long-term fossil and nuclear fuel commitments at December 31,
1997 were as follows:
Minimum
Year Obligations
----------------------
(in millions)
1998 $ 985
1999 799
2000 777
2001 673
2002 614
2003 and beyond 1,635
---------------------------------------------------------------
Total minimum obligations $5,483
===============================================================
Additional commitments for coal and for nuclear fuel will be required in the
future to supply the Company's fuel needs.
Purchase Power Commitments
In connection with the joint ownership arrangement for Plant Vogtle, discussed
in Note 6, the Company has made commitments to purchase portions of OPC's and
MEAG's capacity and energy from this plant. Declining commitments were in effect
during periods of up to seven years following commercial operation and ended in
1996. As discussed in Note 1, the Plant Vogtle declining capacity buyback
expense was levelized over a six-year period which ended in September 1997. In
addition, the Company has commitments regarding a portion of a 5 percent
interest in Plant Vogtle owned by MEAG that are in effect until the latter of
the retirement of the plant or the latest stated maturity date of MEAG's bonds
issued to finance such ownership interest. The payments for capacity are
required whether or not any capacity is available. The energy cost is a function
of each unit's variable operating costs. Except as noted below, the cost of such
capacity and energy is included in purchased power from non-affiliates in the
Company's Statements of Income. Capacity payments totaled $54 million, $68
million, and $76 million in 1997, 1996, and 1995, respectively.
The current projected Plant Vogtle capacity payments are:
Year Amounts
----------------------
(in millions)
1998 $ 57
1999 59
2000 62
2001 61
2002 60
2003 and beyond 771
----------------------------------------------------------------
Total $ 1,070
================================================================
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.
The Company and an affiliate, Alabama Power Company, own equally all of the
outstanding capital stock of Southern Electric Generating Company (SEGCO), which
owns electric generating units with a total rated capacity of 1,020 megawatts,
as well as associated transmission facilities. The capacity of the units has
been sold equally to the Company and Alabama Power under a contract which, in
substance, requires payments sufficient to provide for the operating expenses,
taxes, debt service and return on investment, whether or not SEGCO has any
capacity and energy available. The term of the contract extends automatically
for two-year periods, subject to either party's right to cancel upon two year's
notice. The Company's share of expenses included in purchased power from
affiliates in the Statements of Income, is as follows:
1997 1996 1995
---------------------------------
(in millions)
Energy $45 $47 $44
Capacity 30 30 29
--------------------------------------------------------------
Total $75 $77 $73
==============================================================
Kilowatt-hours 3,038 2,780 2,391
--------------------------------------------------------------
At December 31, 1997, the capitalization of SEGCO consisted of $50 million
of equity and $72 million of long-term debt on which the annual interest
requirement is $4 million.
II-122
NOTES (continued)
Georgia Power Company 1997 Annual Report
The Company has entered into other various long-term commitments for the
purchase of electricity. Total long-term obligations at December 31, 1997 were
as follows:
Year Amounts
----------------------
(in millions)
1998 $ 16
1999 17
2000 21
2001 22
2002 23
2003 and beyond 360
---------------------------------------------------------------
Total $ 459
===============================================================
Operating Leases
The Company has entered into coal rail car rental agreements with various terms
and expiration dates. These expenses totaled $11 million for 1997 and 1996 and
$12 million for 1995. At December 31, 1997, estimated minimum rental commitments
for these noncancelable operating leases were as follows:
Year Amounts
----------------------
(in millions)
1998 $ 11
1999 11
2000 11
2001 12
2002 12
2003 and beyond 132
---------------------------------------------------------------
Total $ 189
===============================================================
5. NUCLEAR INSURANCE
Under the Price-Anderson Amendments Act of 1988, the Company maintains
agreements of indemnity with the NRC that, together with private insurance,
cover third-party liability arising from any nuclear incident occurring at the
Company's nuclear power plants. The act provides funds up to $8.9 billion for
public liability claims that could arise from a single nuclear incident. Each
nuclear plant is insured against this liability to a maximum of $200 million by
private insurance, with the remaining coverage provided by a mandatory program
of deferred premiums that could be assessed, after a nuclear incident, against
all owners of nuclear reactors. The Company could be assessed up to $79 million
per incident for each licensed reactor it operates but not more than an
aggregate of $10 million per incident to be paid in a calendar year for each
reactor. Such maximum assessment for the Company, excluding any applicable state
premium taxes, -- based on its ownership and buyback interests -- is $160
million per incident but not more than an aggregate of $20 million to be paid
for each incident in any one year.
The Company is a member of Nuclear Electric Insurance Limited (NEIL), 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
$10 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 primary
coverage. This excess insurance is also provided by NEIL.
Additionally, NEIL covers the 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 17 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 $11 million for excess property damage and $11 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
II-123
NOTES (continued)
Georgia Power Company 1997 Annual Report
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.
All retrospective assessments, whether generated for liability, property or
replacement power, may be subject to applicable state premium taxes.
6. FACILITY SALES AND JOINT OWNERSHIP
AGREEMENTS
The Company has sold undivided interests in plants Hatch, Wansley, Vogtle, and
Scherer Units 1 and 2 to OPC, an electric membership generation and transmission
corporation; MEAG, a public corporation and an instrumentality of the state of
Georgia; and the City of Dalton, Georgia. The Company has sold an interest in
Plant Scherer Unit 3 to Gulf Power Company, an affiliate. Additionally, the
Company has sold 76.4 percent of Plant Scherer Unit 4 to Florida Power & Light
Company (FP&L) and the remaining 23.6 percent to Jacksonville Electric Authority
(JEA). The Company has also sold transmission facilities to Georgia Transmission
Corporation (formerly OPC's transmission division), MEAG, and the City of
Dalton.
Except as otherwise noted, the Company has contracted to operate and
maintain all jointly owned facilities. The Company includes its proportionate
share of plant operating expenses in the corresponding operating expenses in the
Statements of Income.
As discussed in Note 3, the Company owns 25.4 percent of the Rocky Mountain
pumped storage hydroelectric plant, which began commercial operation in 1995.
OPC owns the remainder, and is the operator of the plant.
The Company owns six of eight 80 megawatt combustion turbine generating
units and 75 percent of the related common facilities at Plant McIntosh.
Savannah Electric and Power Company, an affiliate, owns the remainder and
operates the plant. Four of the Company's six units began commercial operation
during 1994, and the remaining two units began commercial operation in 1995.
The Company and Florida Power Corporation (FPC) jointly own a combustion
turbine unit at Intercession City, Florida, near Orlando. The unit began
commercial operation in January 1997, and is operated by FPC. The Company owns a
one-third interest in the unit, with use of 100 percent of the unit's capacity
from June through September. FPC has the capacity the remainder of the year.
At December 31, 1997, 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) 1,722 50.1
Plant Wansley (coal) 1,730 53.5
Plant Scherer (coal)
Units 1 and 2 1,636 8.4
Unit 3 818 75.0
Plant McIntosh
Common Facilities N/A 75.0
(combustion-turbine)
Rocky Mountain 848 25.4
(pumped storage)
Intercession City 142 33.3
(combustion-turbine)
------------------------------------------------------------------
Accumulated
Facility (Type) Investment Depreciation
----------------------------------------------------------------
(in millions)
Plant Vogtle (nuclear) $3,299* $1,100
Plant Hatch (nuclear) 840 477
Plant Wansley (coal) 298 136
Plant Scherer (coal)
Units 1 and 2 112 44
Unit 3 542 164
Plant McIntosh
Common Facilities
(combustion-turbine) 19 1
Rocky Mountain
(pumped storage) 202 44
Intercession City
(combustion-turbine) 13 **
----------------------------------------------------------------
* Investment net of write-offs.
** Less than $1 million.
II-124
NOTES (continued)
Georgia Power Company 1997 Annual Report
7. LONG-TERM POWER SALES AGREEMENTS
The Company and the operating subsidiaries of Southern Company have long-term
contractual agreements for the sale of capacity and energy to non-affiliated
utilities located outside the system's service area. These agreements consist of
firm unit power sales pertaining to capacity from specific generating units.
Because energy is generally sold at cost under these agreements, it is primarily
the capacity revenues that affect the Company's profitability.
The Company's capacity revenues were as follows:
Year
-------------------------------------
(in millions) (megawatts)
1997 $ 42 159
1996 41 173
1995 53 248
-------------------------------------
Unit power from specific generating plants is being sold to FP&L, FPC, JEA,
and the City of Tallahassee, Florida. Under these agreements, the Company sold
approximately 159 megawatts of capacity in 1997 and is scheduled to sell
approximately 162 megawatts of capacity in 1998 and 1999. In 2000, 129 megawatts
will be sold. After 2000, capacity sales will decline to approximately 105
megawatts -- unless reduced by FP&L, FPC, and JEA -- until the expiration of the
contracts in 2010.
8. INCOME TAXES
At December 31, 1997, tax-related regulatory assets were $688 million and
tax-related regulatory liabilities were $298 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:
1997 1996 1995
-------------------------------
Total provision for income taxes: (in millions)
Federal:
Currently payable $ 352 $325 $349
Deferred -
Current year 49 70 84
Reversal of prior years (68) (41) (55)
Deferred investment tax
credits - - 1
-----------------------------------------------------------------
333 354 379
-----------------------------------------------------------------
State:
Currently payable 65 56 60
Deferred -
Current year 8 12 15
Reversal of prior years (11) (5) (8)
-----------------------------------------------------------------
62 63 67
-----------------------------------------------------------------
Total 395 417 446
-----------------------------------------------------------------
Less:
Income taxes credited
to other income (32) (19) (3)
-----------------------------------------------------------------
Total income taxes
charged to operations $ 427 $436 $449
=================================================================
The tax effects of temporary differences between the carrying amounts of
assets and liabilities in the financial statements and their respective tax
bases, which give rise to deferred tax assets and liabilities, are as follows:
1997 1996
-------------------
(in millions)
Deferred tax liabilities:
Accelerated depreciation $1,732 $1,736
Property basis differences 968 1,038
Other 142 174
-----------------------------------------------------------------
Total 2,842 2,948
-----------------------------------------------------------------
Deferred tax assets:
Other property basis differences 216 225
Federal effect of state deferred taxes 99 100
Other deferred costs 83 93
Disallowed Plant Vogtle buybacks 23 24
Other 14 36
-----------------------------------------------------------------
Total 435 478
-----------------------------------------------------------------
Net deferred tax liabilities 2,407 2,470
Portion included in current assets 11 53
-----------------------------------------------------------------
Accumulated deferred income taxes
in the Balance Sheets $2,418 $2,523
=================================================================
Deferred investment tax credits are amortized over the life of the related
property with such amortization normally applied as a credit to reduce
II-125
NOTES (continued)
Georgia Power Company 1997 Annual Report
depreciation in the Statements of Income. Credits amortized in this manner
amounted to $15 million in 1997, $17 million in 1996, and $22 million in 1995.
At December 31, 1997, all investment tax credits available to reduce federal
income taxes payable had been utilized.
A reconciliation of the federal statutory tax rate to the effective income
tax rate is as follows:
1997 1996 1995
-------- -------- --------
Federal statutory rate 35% 35% 35%
State income tax, net of
federal deduction 4 4 4
Non-deductible book
depreciation 4 3 2
Other (4) (2) (1)
---------------------------------------------------------------
Effective income tax rate 39% 40% 40%
===============================================================
Southern Company and its subsidiaries file a consolidated federal income tax
return. Under a joint consolidated income tax agreement, each subsidiary's
current and deferred tax expense is computed on a stand-alone basis. Tax
benefits from losses of the parent company are allocated to each subsidiary
based on the ratio of taxable income to total consolidated taxable income.
9. CAPITALIZATION
First Mortgage Bond Indenture & Charter
Restrictions
The Company historically has relied on issuances of first mortgage bonds and
preferred stock, in addition to pollution control revenue bonds issued for its
benefit by public authorities, to meet its long-term external financing
requirements. Recently, the Company's financings have consisted of unsecured
debt and trust preferred securities. In this regard, the Company sought and
obtained stockholder approval in 1997 to amend its corporate charter eliminating
restrictions on the amounts of unsecured indebtedness it may incur.
The Company's first mortgage bond indenture contains various restrictions
that remain in effect as long as the bonds are outstanding. At December 31,
1997, $852 million of retained earnings and paid-in capital was unrestricted for
the payment of cash dividends or any other distributions under terms of the
mortgage indenture. If additional first mortgage bonds are issued, supplemental
indentures in connection with those issues may contain more stringent
restrictions than those currently in effect.
The Company's charter previously limited 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, was below 25 percent,
and to 50 percent of such net income if such ratio was less than 20 percent.
These restrictions were removed by a vote of preferred shareholders on December
10, 1997.
Preferred Securities
In December 1994, Georgia Power Capital, L.P., of which the Company is the sole
general partner, issued $100 million of 9 percent mandatorily redeemable
preferred securities. Substantially all of the assets of Georgia Power Capital
are $103 million aggregate principal amount of Georgia Power's 9 percent Junior
Subordinated Deferrable Interest Debentures due December 19, 2024.
Statutory business trusts formed by the Company, of which the Company owns
all the common securities, have issued mandatorily redeemable preferred
securities as follows:
Date of Maturity
Issue Amount Rate Notes Date
-------------------------------------------------------
(millions) (millions)
Trust I 8/1996 $225.00 7.75% $232 6/2036
Trust II 1/1997 175.00 7.60% 180 12/2036
Trust III 6/1997 189.25 7.75% 195 3/2037
Substantially all of the assets of each trust are junior subordinated notes
issued by the Company in the respective approximate principal amounts set forth
above.
The Company considers that the mechanisms and obligations relating to the
preferred securities, taken together, constitute a full and unconditional
guarantee by the Company of Georgia Power Capital's and the Trusts' payment
obligations with respect to the preferred securities.
II-126
NOTES (continued)
Georgia Power Company 1997 Annual Report
Georgia Power Capital, L.P., and the Trusts are subsidiaries of the Company,
and accordingly are consolidated in the Company's financial statements.
Pollution Control Bonds
The Company has incurred obligations in connection with the sale by public
authorities of tax-exempt pollution control revenue bonds. The Company has
authenticated and delivered to trustees an aggregate of $1.3 billion of its
first mortgage bonds, which are pledged as security for its obligations under
pollution control revenue contracts. No interest on these first mortgage bonds
is payable unless and until a default occurs on the installment purchase or loan
agreements.
Details of pollution control bonds are as follows:
Maturity Interest Rates 1997 1996
--------------------------------------------------------------
(in millions)
2000 4.375% $ 50 $ 50
2004-2005 5% to 5.70% 104 143
2011 Variable 10 10
2017 8.375% to 9.375% - 140
2018-2022 6% to 6.35%
& Variable 112 218
2023-2026 5.40% to 6.75%
& Variable 1,110 1,110
2029-2032 Variable 235 -
2034 Variable 50 -
--------------------------------------------------------------
Total pollution control bonds $1,671 $1,671
==============================================================
Senior Notes
In January 1998, the Company issued $145 million of 6 7/8% unsecured senior
notes due December 31, 2047. The senior notes are subordinated to all secured
debt of the Company, including its first mortgage bonds.
Bank Credit Arrangements
At the beginning of 1998, the Company had unused credit arrangements with banks
totaling $1.3 billion, of which $919 million expires at various times during
1998, $300 million expires at June 30, 1999, and $60.3 million expires at May 1,
2000.
The $300 million expiring June 30, 1999, is under revolving credit
arrangements with several banks providing the Company and Alabama Power Company
up to a total credit amount of $300 million. To provide liquidity support for
commercial paper programs, $165 million and $135 million are currently dedicated
to the Company and Alabama Power Company, respectively. However, the allocations
can be changed among the borrowers by notifying the respective banks.
Approximately $1.1 billion of the credit facilities allow for term loans of
between one and three years. Most of the agreements include stated borrowing
rates but also allow for negotiated rates. In addition, these agreements require
payment of commitment fees based on the unused portions of the commitments or
the maintenance of compensating balances with the banks.
Of the Company's total $1.3 billion in unused credit arrangements, a portion
of the lines is dedicated to provide liquidity support to variable rate
pollution control bonds. The credit lines dedicated as of December 31, 1997,
totaled $879 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 1997.
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, 1997 and 1996, the Company had a capitalized
lease obligation for its corporate headquarters building of $87 million with an
interest rate of 8.1 percent. The lease agreement provides for payments that are
minimal in early years and escalate through the first 21 years of the lease. For
ratemaking purposes, the GPSC has treated the lease as an operating lease and
has allowed only the lease payments in cost of service. The difference between
the accrued expense and the lease payments allowed for ratemaking purposes is
being deferred as a cost to be recovered in the future as ordered by the GPSC.
11-127
NOTES (continued)
Georgia Power Company 1997 Annual Report
At December 31, 1997, and 1996, the interest and lease amortization deferred on
the Balance Sheets are $52 million and $51 million, respectively.
Assets Subject to Lien
The Company's mortgage dated as of March 1, 1941, as amended and supplemented,
securing the first mortgage bonds issued by the Company, constitutes a direct
lien on substantially all of the Company's fixed property and franchises.
Securities Due Within One Year
The current portion of the Company's long-term debt and preferred stock is as
follows:
1997 1996
-------------------
(in millions)
First mortgage bonds $ 220 $ 61
Preferred stock - 49
----------------------------------------------------------------
Total $ 220 $ 110
================================================================
The Company's first mortgage bond indenture includes an improvement fund
requirement that amounts to 1 percent of each outstanding series of bonds
authenticated under the indenture prior to January 1 of each year, other than
those issued to collateralize pollution control obligations. The requirement may
be satisfied by June 1 of each year by depositing cash, reacquiring bonds, or by
pledging additional property equal to 1 2/3 times the requirement. The 1998
requirement was met in the first quarter of the year by depositing cash with the
trustee. These funds were used to redeem first mortgage bonds.
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 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 of first mortgage bonds is
outstanding, the Company is prohibited from redeeming for improvement fund
purposes more than 1 percent annually of the original issue amount.
10. QUARTERLY FINANCIAL DATA (UNAUDITED)
Summarized quarterly financial information for 1997 and 1996 is as follows:
Net Income
After
Dividends on
Operating Operating Preferred
Quarter Ended Revenues Income Stock
-------------------------------------------------------------------
(in millions)
--------------------------------------------
March 1997 $ 959 $180 $106
June 1997 1,015 205 131
September 1997 1,407 317 257
December 1997 1,005 159 100
March 1996 $1,029 $192 $114
June 1996 1,134 233 154
September 1996 1,311 339 256
December 1996 943 122 56
-------------------------------------------------------------------
Earnings in the fourth quarter of 1997, compared to the fourth quarter of
1996, increased primarily as a result of higher retail sales and the recognition
in 1996 of an agreement to refund $14 million to municipalities and cooperatives
in Georgia.
The Company's business is influenced by seasonal weather conditions.
II-128
II-129
II-130A
130B
130C
II-131
II-132A
II-132B
II-132C
II-133
II-134A
II-134C
II-135
II-136A
II-136B
II-136C
II-137
II-138A
II-138B
II-138C
II-139
II-140A
II-140B
II-140C
II-141
II-142
II-143
GULF POWER COMPANY
FINANCIAL SECTION
II-144
MANAGEMENT'S REPORT
Gulf Power Company 1997 Annual Report
The management of Gulf Power Company has prepared -- and is responsible for --
the financial statements and related information included in this report. These
statements were prepared in accordance with generally accepted accounting
principles appropriate in the circumstances and necessarily include amounts that
are based on the best estimates and judgments of management. Financial
information throughout this annual report is consistent with the financial
statements.
The Company maintains a system of internal accounting controls to provide
reasonable assurance that assets are safeguarded and that books and records
reflect only authorized transactions of the Company. Limitations exist in any
system of internal controls, however, based on a recognition that the cost of
the system should not exceed its benefits. The Company believes its system of
internal accounting controls maintains an appropriate cost/benefit relationship.
The Company's system of internal accounting controls is evaluated on an
ongoing basis by the Company's internal audit staff. The Company's independent
public accountants also consider certain elements of the internal control system
in order to determine their auditing procedures for the purpose of expressing an
opinion on the financial statements.
The audit committee of the board of directors, composed of directors who are
not employees, provides a broad overview of management's financial reporting and
control functions. Periodically, this committee meets with management, the
internal auditors, and the independent public accountants to ensure that these
groups are fulfilling their obligations and to discuss auditing, internal
controls, and financial reporting matters. The internal auditors and independent
public accountants have access to the members of the audit committee at any
time.
Management believes that its policies and procedures provide reasonable
assurance that the Company's operations are conducted according to a high
standard of business ethics.
In management's opinion, the financial statements present fairly, in all
material respects, the financial position, results of operations, and cash flows
of Gulf Power Company in conformity with generally accepted accounting
principles.
/s/Travis J. Bowden
Travis J. Bowden
President and Chief Executive Officer
/s/Arlan E. Scarbrough
Arlan E. Scarbrough
Chief Financial Officer
February 11, 1998
II-145
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors
of Gulf Power Company:
We have audited the accompanying balance sheets and statements of capitalization
of Gulf Power Company (a Maine corporation and a wholly owned subsidiary of
Southern Company) as of December 31, 1997 and 1996, 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, 1997. 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 II-155 through II-171)
referred to above present fairly, in all material respects, the financial
position of Gulf Power Company as of December 31, 1997 and 1996, and the
results of its operations and its cash flows for each of the three years in the
period ended December 31, 1997, in conformity with generally accepted
accounting principles.
/s/Arthur Andersen LLP
Atlanta, Georgia
February 11, 1998
II-146
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL
CONDITION
Gulf Power Company 1997 Annual Report
RESULTS OF OPERATIONS
Earnings
Gulf Power Company's 1997 net income after dividends on preferred stock was
$57.6 million, a decrease of $0.2 million over the prior year. This change is
primarily attributable to lower residential revenues as a result of milder than
normal weather.
In 1996, earnings were $57.8 million, representing an increase of $0.6
million compared to the prior year. Earnings in 1996 were affected primarily
by higher retail revenues.
The return on average common equity was 13.33 percent for 1997 and 13.27
percent for 1996.
Revenues
Operating revenues decreased in 1997 and increased in 1996 as a result of the
following factors:
Increase (Decrease)
From Prior Year
-------------------------------------
1997 1996 1995
-------------------------------------
(in thousands)
Retail --
Sales growth $ 4,004 $ 7,123 $ 3,647
Weather (5,277) (1,057) 9,749
Regulatory cost
recovery and other (7,837) 5,649 22,502
----------------------------------------------------------------
Total retail (9,110) 11,715 35,898
----------------------------------------------------------------
Sales for resale--
Non-affiliates 496 2,788 (5,698)
Affiliates (1,002) (857) 1,266
----------------------------------------------------------------
Total sales for resale (506) 1,931 (4,432)
Other operating
revenues 1,107 1,642 8,798
----------------------------------------------------------------
Total operating
revenues $(8,509) $15,288 $40,264
================================================================
Percent change (1.3)% 2.5% 7.0%
----------------------------------------------------------------
Retail revenues of $521 million in 1997 decreased $9.1 million or 1.7 percent
from last year, compared with an increase of 2.3 percent in 1996 and 7.4 percent
in 1995. The 1997 reduction was due primarily to a decrease in residential
revenues as a result of mild weather and recovery of lower purchased power
capacity costs.
The decrease in regulatory cost recovery and other retail revenues is
primarily attributable to the recovery of decreased purchased power capacity
costs from affiliated companies. Regulatory cost recovery and other includes
recovery provisions for fuel expense and the energy component of purchased power
costs; energy conservation costs; purchased power capacity costs; and
environmental compliance costs. The recovery provisions equal the related
expenses and have no material effect on net income. See Notes 1 and 3 to the
financial statements under "Revenues and Regulatory Cost Recovery Clauses" and
"Environmental Cost Recovery," respectively, for further information.
Sales for resale were $80.5 million in 1997, decreasing $0.5 million or 0.6
percent from 1996. Revenues from sales to utilities outside the service area
under long-term contracts consist of capacity and energy components. Capacity
revenues reflect the recovery of fixed costs and a return on investment under
the contracts. Energy is generally sold at variable cost. The capacity and
energy components under these long-term contracts were as follows:
1997 1996 1995
----------------------------------------
(in thousands)
Capacity $24,899 $25,400 $25,870
Energy 18,160 19,804 18,598
------------------------------------------------------------
Total $43,059 $45,204 $44,468
============================================================
Capacity revenues decreased slightly in 1997 and 1996, primarily reflecting
the decline in net plant investment related to these sales.
Sales to affiliated companies vary from year to year depending on demand and
the availability and cost of generating resources at each company. These sales
have little impact on earnings.
The increase in other operating revenues in 1997 is primarily attributable to
adjustments to reflect differences between recoverable costs and the amounts
actually reflected in current rates. The increase in other operating revenues
for 1996 was primarily due to increased amounts collected to recover
newly-imposed county franchise fees. These fees are included in taxes other than
income taxes and have no impact on earnings. See Notes 1 and 3 to the financial
statements under "Revenues and Regulatory Cost Recovery Clauses" and
II-147
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 1997 Annual Report
"Environmental Cost Recovery," respectively, for further discussion.
Kilowatt-hour sales for 1997 and percent changes in sales since 1995 are
reported below.
KWH Percent Change
------------ ---------------------------
1997 1997 1996 1995
------------ ---------------------------
(millions)
Residential 4,119 (1.0)% 3.6% 7.0%
Commercial 2,898 3.2 3.7 6.3
Industrial 1,903 5.3 0.7 (2.8)
Other 18 1.6 2.7 (0.1)
------------
Total retail 8,939 1.6 3.0 4.5
Sales for resale
Non-affiliates 1,531 (0.2) 9.9 (1.6)
Affiliates 848 19.5 (6.5) (13.1)
------------
Total 11,318 2.5 3.3 2.2
==================================================================
Retail sales growth was lower in 1997 than in the past two years. Although
the total number of residential customers served increased by more than 9,000 or
3.1% during the year, residential energy sales declined as a result of milder
weather in 1997, compared with more normal weather in 1996. The increase in
energy sales to the industrial class is primarily the result of the
Real-Time-Pricing program. The price structure of this program has encouraged
participating industrial customers to lower their peak demand requirements and
increase their purchases of energy during off-peak periods. See "Future Earnings
Potential" for information on the Company's initiatives to remain competitive
and to meet conservation goals set by the Florida Public Service Commission
(FPSC).
In 1997, energy sales for resale to non-affiliates were essentially
unchanged, decreasing 0.2 percent, and are predominantly related to unit power
sales under long-term contracts to other Florida utilities and bulk power sales
under short-term contracts to other non-affiliated utilities. Energy sales to
affiliated companies vary from year to year as mentioned previously.
Expenses
In 1997, total operating expenses decreased $3.9 million or 0.7 percent from
1996 primarily due to lower fuel and purchased power expenses and maintenance
expenses, offset by higher other operation expenses and depreciation and
amortization expenses. Total operating expenses for 1996 increased $12.7 million
or 2.4 percent from 1995. The increase is due to higher purchased power
expenses, other operation expenses, depreciation expenses, and taxes.
In 1997, fuel and purchased power expenses decreased $10.1 million or 4.4
percent from 1996 reflecting the decrease in fuel and purchased power costs due
to slightly lower fuel costs and increased generation. Fuel and purchased power
expenses for 1996 increased $4 million or 1.8 percent from 1995. The change
reflected the increase in purchased power from affiliated companies due to
scheduled maintenance outages at Plant Crist and Plant Daniel during the first
half of 1996. This increase was partially offset by a slight decrease in fuel
expense reflecting a lower cost of fuel.
The amount and sources of generation and the average cost of fuel per net
kilowatt-hour generated were as follows:
1997 1996 1995
----------------------------
Total generation
(millions of kilowatt-hours) 10,435 10,214 9,828
Sources of generation
(percent)
Coal 99.6 99.4 99.5
Oil and gas 0.4 0.6 0.5
Average cost of fuel per net
kilowatt-hour generated
(cents)
Coal 1.97 1.99 2.08
Oil and gas 5.59 6.41 3.56
Total 1.99 2.02 2.09
-----------------------------------------------------------------
Other operation expenses increased $11.1 million or 9.6% in 1997. The
increase was primarily attributable to higher costs related to the amortization
of prior year buyout and renegotiation of coal supply contracts. Other
contributing factors were implementation costs related to a new customer
accounting system and increased production and distribution costs related to
1997 work force reduction programs. In 1996, other operation expenses increased
$1.8 million or 1.5 percent from the 1995 level. The increase was primarily
attributable to an increase in administrative and general expenses including
costs associated with the approved increase in the Company's annual accrual to
II-148
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 1997 Annual Report
the accumulated provision for property damage to amortize deferred storm charges
and restore the account balance to a reasonable level. See Note 2 to the
financial statements under "Workforce Reduction Programs" for further
discussion.
Maintenance expenses decreased $3.1 million or 6.0 percent in 1997 and
decreased $0.9 million or 1.7 percent in 1996. The decreases were primarily due
to a decrease in scheduled maintenance of production facilities.
Depreciation and amortization expenses increased $1.2 million or 2.2 percent
in 1997 and increased $1.5 million or 2.8 percent in 1996. Both years increases
were primarily due to an increase in depreciation expenses as a result of an
increase in the average investment in distribution property required to serve
the additional customers in the Company's service area.
Federal and state income taxes decreased $2.8 million or 7.4 percent in 1997
primarily due to a decrease in taxable income.
Interest expense in 1997 decreased $0.9 million or 3.0 percent from the prior
year. The decrease is attributable to retirements and refinancings of long-term
debt and reduced interest on notes payable, partially offset by the increase
related to distributions on preferred securities of a subsidiary trust. In 1996,
interest expense increased $0.9 million or 3.2 percent over the prior year. The
increase was attributable to the issuance of $30 million of new first mortgage
bonds in January 1996. The increase in interest on long-term debt was partially
offset by a decrease in interest on notes payable as a result of a lower average
amount of short-term notes outstanding.
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 cost of investments in dollars that have
less purchasing power. While the inflation rate has been relatively low in
recent years, it continues to have an adverse effect on the Company because of
the large investment in long-lived utility plant. Conventional accounting for
historical cost does not recognize this economic loss nor the partially
offsetting gain that arises through financing facilities with fixed-money
obligations, such as long-term debt and preferred stock. Any recognition of
inflation by regulatory authorities is reflected in the rate of return allowed.
Future Earnings Potential
The results of operations for the past three years are not necessarily
indicative of future earnings potential. The level of future earnings depends on
numerous factors ranging from energy sales growth to a potentially less
regulated more competitive environment.
Gulf Power currently operates as a vertically integrated utility providing
electricity to customers within its traditional service area located in
northwest Florida. Prices for electricity provided by the Company to
retail customers are set by the FPSC.
Future earnings in the near term will depend upon growth in energy sales,
which is subject to a number of factors. Traditionally, these factors have
included weather, competition, changes in contracts with neighboring utilities,
energy conservation practiced by customers, the elasticity of demand, and the
rate of economic growth in the Company's service area.
The electric utility industry in the United States is currently undergoing a
period of change as a result of regulatory and competitive factors. Among the
primary agents of change has been the Energy Policy Act of 1992 (Energy Act).
The Company is positioning the business to meet the challenge of this major
change in the traditional practice of selling electricity. The Energy Act allows
independent power producers (IPPs) to access the Company's transmission network
in order to sell electricity to other utilities. This enhances the incentive for
IPPs to build cogeneration plants for industrial and commercial customers and
sell energy generation to other utilities. The Company has and will continue to
evaluate opportunities to partner and participate in profitable cogeneration
projects. In 1997, partnering with one of the Company's largest industrial
customers, 15 megawatts of Company-owned cogeneration is being constructed on
the customer's plant site. Also, electricity sales for resale rates are being
driven down by wholesale transmission access and numerous potential new energy
suppliers, including power marketers and brokers. The Company is aggressively
working to maintain and expand its share of wholesale sales in the southeastern
power markets.
II-149
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 1997 Annual Report
Although the Energy Act does not permit retail customer access, it was a
major catalyst for the current restructuring and consolidation taking place
within the utility industry. Numerous federal and state initiatives to promote
wholesale and retail competition are at varying stages. Among other things,
these initiatives allow customers to choose their electricity provider. As the
initiatives materialize, the structure of the utility industry could radically
change. Some states have approved initiatives that result in a separation of the
ownership and/or operation of generating facilities from the ownership and/or
operation of transmission and distribution facilities. While various
restructuring and competition initiatives have been or are being discussed in
Florida, none have been enacted to date. Enactment would require numerous issues
to be resolved, including significant ones relating to transmission pricing and
recovery of any stranded investments. The inability of the Company to recover
its investments, including the regulatory assets described in Note 1 to the
financial statements, could have a material adverse effect on the financial
condition of the Company. The Company is attempting to minimize or reduce its
cost exposure.
Continuing to be a low-cost producer could provide significant opportunities
to increase market share and profitability in markets that evolve with changing
regulation. Conversely, 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.
The FPSC set conservation goals and approved programs to accomplish the goals
beginning in 1995. The goals require conservation programs which reduce 154
megawatts of summer peak demand and 65 million KWH of sales by the year 2004.
The Company can experience net growth as long as the filed programs achieve the
intended reductions in peak demand and KWH sales. In response to these goals and
seeking to remain competitive with other electric utilities, the Company has
developed initiatives which emphasize price flexibility and competitive offering
of energy efficiency products and services. These initiatives will enable
customers to lower or alter their peak energy requirements. Besides promoting
energy efficiency, another benefit of these initiatives could be the ability to
defer the need to construct additional generating capacity.
On September 3, 1996, the FPSC approved a new optional Commercial/Industrial
Service Rider (CISR), which is applicable to the rate schedules for the
Company's largest existing and potential customers who are able to show they
have viable alternatives to purchasing the Company's energy services. The CISR,
approved as a pilot program, provides the flexibility needed to enable the
Company to offer its services in a more competitive manner to these customers.
During 1997, the publicity of the CISR ruling, increased competitive pressures,
and general awareness of customer choice pilots and proposals across the country
has stimulated interest on the part of customers in custom tailored offerings.
The Company has participated in one-on-one discussions with many of these
customers, and has negotiated and executed two Contract Service Agreements
within the CISR pilot program in 1997.
The Company is heavily dependent upon complex computer systems for all phases
of its operations. The year 2000 issue--common to most corporations--concerns
the inability of certain software and databases to properly recognize date
sensitive information beginning related to the year 2000 and thereafter. This
problem could result in a material disruption to the Company's operation, if not
corrected. The Company has assessed and developed a detailed strategy to prevent
or at least minimize problems related to the year 2000 issue. In 1997, resources
were committed and implementation began to modify the affected information
systems. Total costs related to the project for Southern Company are estimated
to be approximately $85 million, of which $8 million was spent in 1997. The
Company's total costs related to the project are estimated to be approximately
$5 million, of which $0.5 million was spent in 1997. Most all remaining costs
will be expensed in 1998. Implementation is currently on schedule and all costs
are being expensed as incurred. The degree of success of this project cannot be
determined at this time. However, management believes that the final outcome
will not have a material adverse effect on the operations of the Company.
II-150
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 1997 Annual Report
Compliance costs related to current and future environmental laws and
regulations could affect earnings if such costs are not fully recovered. The
Clean Air Act and other important environmental items are discussed later under
"Environmental Matters." Also, Florida legislation adopted in 1993 that provides
for recovery of prudent environmental compliance costs is discussed in Note 3 to
the financial statements under "Environmental Cost Recovery."
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 that are not specifically recoverable, and
determine if any other assets have been impaired. See Note 1 to the financial
statements under "Regulatory Assets and Liabilities" for additional information.
Exposure to Market Risks
Due to cost-based rate regulation, the Company has limited exposure to market
volatility in interest rates and prices of electricity. To mitigate residual
risks relative to movements in electricity prices, the Company enters into fixed
price contracts for the purchase and sale of electricity through the wholesale
electricity market. Realized gains and losses are recognized in the income
statements as incurred. At December 31, 1997, exposure from these activities was
not material to the Company's financial position, results of operations, or cash
flows.
New Accounting Standards
The FASB has issued Statement No. 130, Reporting Comprehensive Income, which
will be effective in 1998. This statement establishes standards for reporting
and display of comprehensive income and its components in a full set of general
purpose financial statements. The objective of the statement is to report a
measure of all changes in equity of an enterprise that result from transactions
and other economic events of the period other than transactions with owners
(comprehensive income). Comprehensive income is the total of net income and all
other non-owner changes in equity. These rules will be adopted by the Company
in 1998.
The FASB has issued Statement No. 131, Disclosure about Segments of an
Enterprise and Related Information. This statement requires that a public
business enterprise report financial and descriptive information about its
reportable operating segments. Generally, financial information is required to
be reported on the basis that it is used by the chief operating decision maker
in deciding how to allocate resources and in assessing performance. This
statement also establishes standards for related disclosures about products and
services, geographic areas, and major customers. The Company adopted the new
rules in 1997, which do not have a significant impact on the Company's financial
reporting. However, this conclusion may change as industry restructuring and
competitive factors influence the Company's operations.
FINANCIAL CONDITION
Overview
The Company's financial condition continues to be very solid. During 1997, gross
property additions were $54.3 million. Funds for the property additions were
provided by internal sources. See the Statements of Cash Flows for further
details.
Financing Activities
The Company continued to lower its financing costs by issuing new long
term-notes and trust preferred securities and retiring higher-cost issues in
1997. The Company sold $40 million of trust preferred securities, $40.9 million
of pollution control bonds, and $20 million of junior subordinated notes.
Retirements, including maturities during 1997, totaled $25 million of first
mortgage bonds, $40.9 million of pollution control bonds, $75.9 million of
preferred stock, and $16 million of long-term bank notes. The refinancing of
$40.9 million in pollution control bonds and $39.5 million in preferred stock
will result in savings of over $2.6 million annually. See the Statements of Cash
Flows for further details.
Composite financing rates for the years 1995 through 1997 as of year end were
as follows:
1997 1996 1995
------------------------------
Composite interest rate on
long-term debt 5.9% 6.1% 6.5%
Composite preferred stock
dividend rate 6.1% 6.4% 6.4%
----------------------------------------------------------------
II-151
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 1997 Annual Report
The decrease in the composite interest rate on long-term debt from 1995 to
1997 reflects the Company's efforts to refinance higher-cost debt. The decrease
in the composite preferred stock dividend rate in 1997 was primarily due to a
decrease in dividends on the Company's adjustable rate preferred stock,
reflecting lower interest rates, and the retirement of higher coupon rate
preferred stock.
Capital Requirements for Construction
The Company's gross property additions, including those amounts related to
environmental compliance, are budgeted at $192 million for the three years
beginning in 1998 ($68 million in 1998, $62 million in 1999, and $62 million in
2000). Actual construction costs may vary from this estimate because of changes
in such factors as: business conditions; environmental regulations; load
projections; the cost and efficiency of construction labor, equipment, and
materials; and the cost of capital. In addition, there can be no assurance that
costs related to capital expenditures will be fully recovered. The Company does
not have any major generating plants under construction, however, significant
construction related to maintaining and upgrading transmission and distribution
facilities and generating plants will continue.
Other Capital Requirements
In addition to the funds needed for the construction program, approximately $80
million will be required by the end of 2000 in connection with maturities of
long-term debt. Also, the Company will continue to retire higher-cost debt and
preferred stock and replace these securities with lower-cost capital as market
conditions and terms of the instruments permit.
Environmental Matters
In November 1990, the Clean Air Act was signed into law. Title IV of the Clean
Air Act -- the acid rain compliance provision of the law -- significantly
affected the Company. Specific reductions in sulfur dioxide and nitrogen oxide
emissions from fossil-fired generating plants are required in two phases. Phase
I compliance began in 1995 and initially affected 28 generating units of
Southern Company. As a result of Southern Company's compliance strategy, an
additional 22 generating units were brought into compliance with Phase I
requirements. Phase II compliance is required in 2000, and all fossil-fired
generating plants will be affected.
Southern Company achieved Phase I sulfur dioxide compliance at the affected
plants by switching to low-sulfur coal, which required some equipment upgrades.
Construction expenditures for Phase I compliance totaled approximately $300
million for Southern Company, including approximately $42 million for Gulf
Power.
For Phase II sulfur dioxide compliance, Southern Company could use emission
allowances, increase fuel switching, and/or install flue gas desulfurization
equipment at selected plants. Also, equipment to control nitrogen oxide
emissions will be installed on additional system fossil-fired units as required
to meet Phase II limits. Current compliance strategy for Phase II and ozone
non-attainment could require total estimated construction expenditures for
Southern Company of approximately $70 million, of which $55 million remains to
be spent. Phase II compliance is not expected to have a material impact on Gulf
Power.
Following adoption of legislation in April of 1992 allowing electric
utilities in Florida to seek FPSC approval of their Clean Air Act Compliance
Plans, Gulf Power filed its petition for approval. The FPSC approved the
Company's plan for Phase I compliance, deferring until a later date approval of
its Phase II Plan.
In 1993, the Florida Legislature adopted legislation that allows a utility to
petition the FPSC for recovery of prudent environmental compliance costs that
are not being recovered through base rates or any other recovery mechanism. The
legislation is discussed in Note 3 to the financial statements under
"Environmental Cost Recovery." Substantially all of the costs for the Clean Air
Act and other new environmental legislation discussed below are expected to be
recovered through the Environmental Cost Recovery Clause.
In July 1997, the Environmental Protection Agency (EPA) revised the national
ambient air quality standards for ozone and particulate matter. This revision
makes the standards significantly more stringent. Also, in October 1997, the EPA
issued a proposed regional ozone rule--if implemented--that could require
substantial further reductions in NOx emissions from fossil-fueled generating
facilities. Implementation of the standards and the proposed rule could result
in significant additional compliance costs and capital expenditures that cannot
be determined at this time.
II-152
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 1997 Annual Report
The EPA and state environmental regulatory agencies are reviewing and
evaluating various other matters including: emission control strategies for
ozone non-attainment areas; additional controls for hazardous air pollutant
emissions; and hazardous waste disposal requirements. The impact of new
standards will depend on the development and implementation of applicable
regulations.
Gulf Power 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 substantial costs to clean up properties.
The Company conducts studies to determine the extent of any required cleanup
costs and has recognized in the financial statements costs to clean up known
sites. For additional information, see Note 3 to the financial statements under
"Environmental Cost Recovery."
Several major pieces of environmental legislation are being considered for
reauthorization or amendment by Congress. These include: the Clean Air Act; the
Clean Water Act; the Comprehensive Environmental Response, Compensation and
Liability Act; the Resource Conservation and Recovery Act; the Toxic Substances
Control Act; and the Endangered Species Act. Changes to these laws could affect
many areas of the Company's operations. The full impact of any such changes
cannot be determined at this time.
Compliance with possible additional legislation related to global climate
change, electric and magnetic fields, and other environmental 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 electric and magnetic fields.
Sources of Capital
At December 31, 1997, the Company had $4.7 million of cash and cash equivalents
and $32.5 million of unused committed lines of credit with banks to meet its
short-term cash needs. Refer to Statements of Cash Flows for details related to
the Company's financing activities. See Note 5 to the financial statements under
"Bank Credit Arrangements" for additional information.
In January 1998, Gulf Power Capital Trust II (Trust II), of which the Company
owns all the common securities, issued $45 million of 7.0 percent mandatorily
redeemable preferred securities. See Note 9 to the financial statements under
"Company Obligated Mandatorily Redeemable Preferred Securities" for additional
information.
It is anticipated that the funds required for construction and other
purposes, including compliance with environmental regulations, will be derived
from operations; the sale of additional first mortgage bonds, long-term
unsecured debt, pollution control bonds, and preferred securities; bank notes;
and capital contributions from Southern Company. If the attractiveness of
current short-term interest rates continues, the Company may maintain a higher
level of short-term indebtedness than has historically been true. 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 coverage ratios are sufficient to permit, at present
interest and preferred dividend levels, any foreseeable security sales. In
December 1997, the Company obtained stockholder approval to amend the corporate
charter including the elimination of the restrictions on the amount of unsecured
indebtedness allowed. The amount of securities which the Company will be
permitted to issue in the future will depend upon market conditions and other
factors prevailing at that time.
Cautionary Statement Regarding Forward-Looking Information
Gulf Power Company's 1997 Annual Report contains forward-looking statements in
addition to historical information. The Company cautions that there are various
important factors that could cause actual results to differ materially from
those indicated in the forward-looking statements; accordingly, there can be no
assurance that such indicated results will be realized. These factors include
legislative and regulatory initiatives regarding deregulation and restructuring
of the electric utility industry; the extent and timing of the entry of
additional competition in the Company's markets; potential business
strategies--including acquisitions or dispositions of assets or internal
restructuring--that may be pursued by the company; state and federal rate
II-153
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 1997 Annual Report
regulation; changes in or application of environmental and other laws and
regulations to which the Company is subject; political, legal and economic
conditions and developments; financial market conditions and the results of
financing efforts; changes in commodity prices and interest rates; weather and
other natural phenomena; and other factors discussed in the reports--including
Form 10-K--filed from time to time by the Company with the Securities and
Exchange Commission.
II-154
STATEMENTS OF INCOME
For the Years Ended December 31, 1997, 1996, and 1995
Gulf Power Company 1997 Annual Report
II-155
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II-157
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II-160
II-161
NOTES TO FINANCIAL STATEMENTS
Gulf Power Company 1997 Annual Report
1. SUMMARY OF SIGNIFICANT ACCOUNTING
POLICIES
General
Gulf Power Company is a wholly owned subsidiary of Southern Company, which is
the parent company of five operating companies, a system service company,
Southern Communications Services (Southern Communications), Southern Energy,
Inc. (Southern Energy), Southern Nuclear Operating Company (Southern Nuclear),
Southern Company Energy Solutions, and other direct and indirect subsidiaries.
The operating companies (Alabama Power, Georgia Power, Gulf Power, Mississippi
Power, and Savannah Electric) provide electric service in four southeastern
states. Gulf Power Company provides electric service to the northwest panhandle
of Florida. Contracts among the operating companies -- dealing with jointly
owned generating facilities, interconnecting transmission lines, and the
exchange of electric power -- are regulated by the Federal Energy Regulatory
Commission (FERC) or the Securities and Exchange Commission. The system service
company provides, at cost, specialized services to Southern Company and
subsidiary companies. Southern Communications provides digital wireless
communications services to the operating companies and also markets these
services to the public within the Southeast. Worldwide, Southern Energy develops
and manages electricity and other energy related projects, including domestic
energy trading and marketing. Southern Nuclear provides services to Southern
Company's nuclear power plants. Southern Company Energy Solutions develops new
business opportunities related to energy products and services.
Southern Company is registered as a holding company under the Public Utility
Holding Company Act of 1935 (PUHCA). Both Southern Company and its subsidiaries
are subject to the regulatory provisions of the PUHCA. The Company is also
subject to regulation by the FERC and the Florida Public Service Commission
(FPSC). The Company follows generally accepted accounting principles and
complies with the accounting policies and practices prescribed by the FPSC. The
preparation of financial statements in conformity with generally accepted
accounting principles requires the use of estimates, and the actual results may
differ from those estimates.
Certain prior years' data presented in the financial statements have been
reclassified to conform with current year presentation.
Regulatory Assets and Liabilities
The Company is subject to the provisions of Financial Accounting Standards Board
(FASB) Statement No. 71, Accounting for the Effects of Certain Types of
Regulation. Regulatory assets represent probable future revenues to the Company
associated with certain costs that are expected to be recovered from customers
through the ratemaking process. Regulatory liabilities represent probable future
reductions in revenues associated with amounts that are expected to be credited
to customers through the ratemaking process. Regulatory assets and (liabilities)
reflected in the Balance Sheets at December 31 relate to the following:
1997 1996
-------------------------
(in thousands)
Deferred income tax debits $ 26,586 $ 28,313
Deferred loss on reacquired debt 20,494 20,386
Environmental remediation 7,338 7,577
Current & deferred
coal contract costs 4,456 29,515
Vacation pay 4,057 4,055
Deferred storm charges 703 3,275
Regulatory clauses over
recovery, net (3,387) (1,740)
Deferred income tax credits (56,935) (64,354)
Other, net (629) (1,202)
-----------------------------------------------------------------
Total $ 2,683 $ 25,825
=================================================================
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 net regulatory assets and liabilities that are not specifically
recoverable through regulated rates. In addition, the Company would be required
to determine any impairment to other assets, including plant, and write down the
assets, if impaired, to their fair value.
II-162
NOTES (continued)
Gulf Power Company 1997 Annual Report
Revenues and Regulatory Cost Recovery Clauses
The Company accrues revenues for service rendered but unbilled at the end of
each fiscal period. The Company has a diversified base of customers and no
single customer or industry comprises 10 percent or more of revenues. In 1997,
uncollectible accounts continued to average significantly less than 1 percent of
revenues.
Fuel costs are expensed as the fuel is used. The Company's electric rates
include provisions to periodically adjust billings for fluctuations in fuel, the
energy component of purchased power costs, and certain other costs. The Company
also has similar cost recovery clauses for energy conservation costs, purchased
power capacity costs, and environmental compliance costs. Revenues are adjusted
monthly for differences between recoverable costs and amounts actually reflected
in current rates.
Depreciation and Amortization
Depreciation of the original cost of depreciable utility plant in service is
provided primarily by using composite straight-line rates, which approximated
3.6 percent in 1997, 1996, and 1995. 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. Also,
the provision for depreciation expense includes an amount for the expected cost
of removal of facilities.
Income Taxes
The Company uses the liability method of accounting for deferred income taxes
and provides deferred income taxes for all significant income tax temporary
differences. Investment tax credits utilized are deferred and amortized to
income over the average lives of the related property. The Company is included
in the consolidated federal income tax return of Southern Company. See Note 8
for further information related to income taxes.
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. AFUDC amounts for 1997, 1996, and 1995 were immaterial and
are included in other, net and other interest charges in the Statements of
Income.
Utility Plant
Utility plant is stated at original cost. Original cost includes: materials;
labor; minor items of property; appropriate administrative and general costs;
payroll-related costs such as taxes, pensions, and other benefits; and the
estimated cost of funds used during construction. The cost of maintenance,
repairs, and replacement of minor items of property is charged to maintenance
expense. The cost of replacements of property (exclusive of minor items of
property) is charged to utility plant.
Cash and Cash Equivalents
For purposes of the Statements of Cash Flows, temporary cash investments are
considered cash equivalents. Temporary cash investments are securities with
original maturities of 90 days or less.
Financial Instruments
The Company's financial instruments for which the carrying amount did not equal
fair value at December 31 were as follows:
Carrying Fair
Amount Value
----------------------------
(in thousands)
Long-term debt
At December 31, 1997 $350,320 $356,766
At December 31, 1996 $372,852 $373,394
Capital trust preferred
securities:
At December 31, 1997 $40,000 $40,800
At December 31, 1996 - -
-------------------------------------------------------------
II-163
NOTES (continued)
Gulf Power Company 1997 Annual Report
The fair values for long-term debt and preferred securities were based on
either closing market prices or closing prices of comparable instruments.
Materials and Supplies
Generally, materials and supplies include the cost of transmission,
distribution, and generating plant materials. Materials are charged to inventory
when purchased and then expensed or capitalized to plant, as appropriate, when
installed.
Provision for Injuries and Damages
The Company is subject to claims and suits arising in the ordinary course of
business. As permitted by regulatory authorities, the Company provides for the
uninsured costs of injuries and damages by charges to income amounting to $1.2
million annually. The expense of settling claims is charged to the provision to
the extent available. The accumulated provision of $1.4 million and $1.8 million
at December 31, 1997 and 1996, respectively, is included in miscellaneous
current liabilities in the accompanying Balance Sheets.
Provision for Property Damage
The Company is self-insured for the full cost of storm and other damages to its
transmission and distribution property. At December 31, 1997, the accumulated
provision for property damage had a negative balance of $0.7 million. The
negative balance was reclassified to deferred storm charges in the accompanying
Balance Sheets. In December 1995, the FPSC approved the Company's request to
increase the amount of its annual accrual to the accumulated provision for
property damage account from $1.2 million to $3.5 million and approved a target
level for the accumulated provision account between $25.1 and $36 million. The
FPSC has also given the Company the flexibility to increase its annual accrual
amount above $3.5 million, when the Company believes it is in a position to do
so, until the account balance reaches $12 million. The Company accrued $3.9
million in 1997 and $4.5 million in 1996 to the accumulated provision for
property damage. The expense of repairing damages from major storms and other
uninsured property damages is charged to the provision account.
2. RETIREMENT BENEFITS
Pension Plan
The Company has a defined benefit, trusteed, non-contributory pension plan that
covers substantially all regular employees. Benefits are based on one of the
following formulas: years of service and final average pay or years of service
and a flat-dollar benefit. The Company uses the "entry age normal method with a
frozen initial liability" actuarial method for funding purposes, subject to
limitations under federal income tax regulations. Amounts funded to the pension
trust fund are primarily invested in equity and fixed-income securities. FASB
Statement No. 87, Employers' Accounting for Pension, requires use of the
"projected unit credit" actuarial method for financial reporting purposes.
Postretirement Benefits
The Company provides certain medical care and life insurance benefits for
retired employees. Substantially all employees may become eligible for these
benefits when they retire. Trusts are funded to the extent deductible under
federal income tax regulations or to the extent required by the Company's
regulatory commissions. Amounts funded are primarily invested in equity and
fixed-income securities. FASB Statement No. 106, Employers' Accounting for
Postretirement Benefits Other Than Pensions, requires that medical care and life
insurance benefits for retired employees be accounted for on an accrual basis
using a specified actuarial method, "benefit/years-of-service."
II-164
NOTES (continued)
Gulf Power Company 1997 Annual Report
Funded Status and Cost of Benefits
The funded status of the plans and reconciliation to amounts reflected in the
Balance Sheets at December 31 are as follows:
Pension
-------------------------
1997 1996
-------------------------
(in thousands)
Actuarial present value of
benefit obligation:
Vested benefits $ 97,180 $ 87,245
Non-vested benefits 3,886 5,101
-------------------------------------------------------------
Accumulated benefit obligation 101,066 92,346
Additional amounts related to
projected salary increases 29,728 31,121
-------------------------------------------------------------
Projected benefit obligation 130,794 123,467
Less:
Fair value of plan assets 222,196 191,152
Unrecognized net gain (80,497) (58,900)
Unrecognized prior service cost 5,244 5,618
Unrecognized transition asset (5,764) (6,485)
-------------------------------------------------------------
Prepaid asset recognized in
the Balance Sheets $ 10,385 $ 7,918
=============================================================
Postretirement Benefits
---------------------------
1997 1996
---------------------------
(in thousands)
Actuarial present value of
benefit obligation:
Retirees and dependents $17,363 $10,478
Employees eligible to retire 4,537 5,484
Other employees 17,769 17,694
----------------------------------------------------------------
Accumulated benefit obligation 39,669 33,656
Less:
Fair value of plan assets 9,813 7,996
Unrecognized net loss 3,930 1,531
Unrecognized transition
obligation 5,435 5,790
----------------------------------------------------------------
Accrued liability recognized in
the Balance Sheets $20,491 $18,339
================================================================
The weighted average rates assumed in the actuarial calculations were:
1997 1996 1995
------------------------------
Discount 7.5% 7.8% 7.3%
Annual salary increase 5.0% 5.3% 4.8%
Long-term return on plan
assets 8.5% 8.5% 8.5%
-----------------------------------------------------------------
An additional assumption used in measuring the accumulated postretirement
benefit obligation was a weighted average medical care cost trend rate of 8.8
percent for 1997, decreasing gradually to 5.5 percent through the year 2005 and
remaining at that level thereafter. An annual increase in the assumed medical
care cost trend rate of 1 percent would increase the accumulated benefit
obligation at December 31, 1997, by $3.2 million and the aggregate of the
service and interest cost components of the net retiree cost by $278 thousand.
Components of the plans' net costs are shown below:
Pension
------------------------------------
1997 1996 1995
------------------------------------
(in thousands)
Benefits earned during
the year $ 3,897 $ 3,880 $ 3,867
Interest cost on projected
benefit obligation 9,301 9,129 8,042
Actual (return) loss on
plan assets (32,924) (21,021) (33,853)
Net amortization
and deferral 17,246 5,920 19,619
------------------------------------------------------------------
Net pension income $ (2,480) $ (2,092) $(2,325)
==================================================================
Of the above net pension amounts, pension income of $1.8 million in 1997,
$1.5 million in 1996, and $1.8 million in 1995 were recorded in operating
expenses, and the remainder was recorded in construction and other accounts.
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NOTES (continued)
Gulf Power Company 1997 Annual Report
Postretirement Benefits
--------------------------------
1997 1996 1995
--------------------------------
(in thousands)
Benefits earned during the year $ 896 $ 939 $1,259
Interest cost on accumulated
benefit obligation 2,845 2,330 2,520
Amortization of transition
obligation 356 356 853
Actual (return) loss on plan assets (1,166) (797) (1,268)
Net amortization and deferral 709 318 742
-------------------------------------------------------------------
Net postretirement cost $3,640 $3,146 $4,106
===================================================================
Of the above net postretirement costs recorded, $2.7 million in 1997, $2.3
million in 1996, and $3.1 million in 1995 were charged to operating expenses,
and the remainder was recorded in construction and other accounts.
Work Force Reduction Programs
The Company recorded costs related to work force reductions programs of $1.4
million in 1997, $1.2 million in 1996, and $7 million in 1995. The Company has
also incurred its pro rata share for the costs of affiliated companies'
programs. The costs related to these programs were $1.3 million for 1997, $2.1
million for 1996, and $1 million for 1995. The costs related to work force
reductions have been expensed to operation expenses.
3. LITIGATION AND REGULATORY MATTERS
FERC Reviews Equity Returns
In May 1991, the FERC ordered that hearings be conducted concerning the
reasonableness of the operating companies' wholesale rate schedules and
contracts that have a return on common equity of 13.75 percent or greater. The
contracts that could be affected by the hearings include substantially all of
the transmission, unit power, long-term power and other similar contracts.
In August 1992, a FERC administrative law judge issued an opinion that
changes in rate schedules and contracts were not necessary and that the FERC
staff failed to show how any changes were in the public interest. The FERC staff
has filed exceptions to the administrative law judge's opinion, and the matter
remains pending before the FERC.
In August 1994, the FERC instituted another proceeding based on substantially
the same issues as in the 1991 proceeding. In November 1995, a FERC
administrative law judge issued an opinion that the FERC staff failed to meet
its burden of proof, and therefore, no change in the equity return was
necessary. The FERC staff has filed exceptions to the administrative law judge's
opinion, and the matter remains pending before the FERC.
If the rates of return on common equity recommended by the FERC staff were
applied to all of the schedules and contracts involved in both proceedings, as
well as certain other contracts that reference these proceedings in determining
return on common equity, and if refunds were ordered, the amount of refunds
could range up to approximately $194 million for Southern Company, including
approximately $13 million for the Company at December 31, 1997. Although
management believes that rates are not excessive and that refunds are not
justified, the final outcome of this matter cannot now be determined.
Environmental Cost Recovery
In April 1993, the Florida Legislature adopted legislation for an Environmental
Cost Recovery Clause (ECRC), which allows a utility to petition the FPSC for
recovery of all prudent environmental compliance costs that are not being
recovered through base rates or any other recovery mechanism. Such environmental
costs include operation and maintenance expense, emission allowance expense,
depreciation, and a return on invested capital.
In January 1994, the FPSC approved the Company's initial petition under the
ECRC for recovery of environmental costs. Beginning with this initial period
through September 1996, recovery under the ECRC was determined semi-annually. In
August 1996, the FPSC approved annual recovery periods beginning with the
October 1996 through September 1997 period. Recovery includes a true-up of the
prior period and a projection of the ensuing period. During 1997 and 1996, the
Company recorded ECRC revenues of $10.2 million and $11.0 million, respectively.
At December 31, 1997, the Company's liability for the estimated costs of
environmental remediation projects for known sites was $7.3 million. These
estimated costs are expected to be expended during the period 1998 to 2002.
II-166
NOTES (continued)
Gulf Power Company 1997 Annual Report
These projects have been approved by the FPSC for recovery through the ECRC
discussed above. Therefore, the Company recorded $1.7 million in current assets
and current liabilities, and $5.6 million in deferred assets and liabilities
representing the future recoverability of these costs.
4. CONSTRUCTION PROGRAM
The Company is engaged in a continuous construction program, the cost of which
is currently estimated to total $68 million in 1998, $62 million in 1999, and
$62 million in 2000. The construction program is subject to periodic review and
revision, and actual construction costs may vary from the above estimates
because of numerous factors. These factors include changes in business
conditions; revised load growth estimates; changes in environmental regulations;
increasing costs of labor, equipment and materials; and cost of capital. At
December 31, 1997, significant purchase commitments were outstanding in
connection with the construction program. The Company does not have any major
generating plants under construction, however, significant construction will
continue related to transmission and distribution facilities and the upgrading
and extension of the useful lives of generating plants.
See Management's Discussion and Analysis under "Environmental Matters" for
information on the impact of the Clean Air Act Amendments of 1990 and other
environmental matters.
5. FINANCING AND COMMITMENTS
General
Current projections indicate that funds required for construction and other
purposes, including compliance with environmental regulations, will be derived
primarily from internal sources. Requirements not met from internal sources will
be derived from the sale of additional first mortgage bonds, long-term unsecured
debt, pollution control bonds, and preferred securities; bank notes; and capital
contributions from Southern Company. In addition, the Company may issue
additional long-term debt and preferred securities primarily for debt maturities
and redemptions of higher-cost securities.
Bank Credit Arrangements
At December 31, 1997, the Company had $41.5 million of lines of credit with
banks subject to renewal June 1 of each year, of which $32.5 million remained
unused. In addition, the Company has two unused committed lines of credit
totaling $61.9 million that were established for liquidity support of its
variable rate pollution control bonds. In connection with these credit lines,
the Company has agreed to pay commitment fees and/or to maintain compensating
balances with the banks. The compensating balances, which represent
substantially all of the cash of the Company except for daily working funds and
like items, are not legally restricted from withdrawal. In addition, the Company
has bid-loan facilities with ten major money center banks that total $180
million, of which $38 million was committed at December 31, 1997.
Assets Subject to Lien
The Company's mortgage, which secures the first mortgage bonds issued by the
Company, constitutes a direct first lien on substantially all of the Company's
fixed property and franchises.
Fuel Commitments
To supply a portion of the fuel requirements of its generating plants, the
Company has entered into long-term commitments for the procurement of fuel. In
most cases, these contracts contain provisions for price escalations, minimum
purchase levels, and other financial commitments. Total estimated long-term
obligations at December 31, 1997, were as follows:
Year Fuel
------- ----------------
(in millions)
1998 $82
1999 77
2000 70
2001 72
2002 74
2003 - 2007 408
--------------------------------------------------------
Total commitments $783
=========================================================
In 1988, the Company made an advance payment of $60 million to a coal
supplier under an arrangement to lower the cost of future coal purchased under
an existing contract. This amount is being amortized to expense on a per ton
II-167
NOTES (continued)
Gulf Power Company 1997 Annual Report
basis over a ten-year period. The remaining unamortized amount was $2.7
million at December 31, 1997.
In December 1995, the Company made another payment of $22 million to the same
coal supplier under an arrangement to lower the cost of future coal and/or to
suspend the purchase of coal under an existing contract for 25 months. This
amount is being amortized to expense on a per ton basis through the first
quarter of 1998. The remaining unamortized amount was $1.8 million at December
31, 1997.
The amortization expense of these contract buyouts and renegotiations is
being recovered through the fuel cost recovery clause discussed under "Revenues
and Regulatory Cost Recovery Clauses" in Note 1.
Lease Agreements
In 1989, the Company and Mississippi Power jointly entered into a twenty-two
year operating lease agreement for the use of 495 aluminum railcars. In 1994, a
second lease agreement for the use of 250 additional aluminum railcars was
entered into for twenty-two years. Both of these leases are for the
transportation of coal to Plant Daniel. The Company has the option after three
years from the date of the original contract on the second lease agreement to
purchase the railcars at the greater of the termination value or the fair market
value. Additionally, at the end of each lease term, the Company has the option
to renew the lease. In 1997, three additional lease agreements for 120 cars each
were entered into for three years, with a monthly renewal option for up to an
additional nine months.
The Company, as a joint owner of Plant Daniel, is responsible for one half of
the lease costs. The lease costs are charged to fuel inventory and are allocated
to fuel expense as the fuel is used. The Company's share of the lease costs
charged to fuel inventories was $2.3 million in 1997 and $1.7 million in 1996.
The annual amounts for 1998 through 2002 will be $2.8 million, $2.8 million,
$2.1 million, $1.7 million, and $1.7 million respectively, and after 2002 will
total $17.8 million.
6. JOINT OWNERSHIP AGREEMENTS
The Company and Mississippi Power jointly own Plant Daniel, a steam-electric
generating plant located in Jackson County, Mississippi. In accordance with an
operating agreement, Mississippi Power acts as the Company's agent with respect
to the construction, operation, and maintenance of the plant.
The Company and Georgia Power jointly own Plant Scherer Unit No. 3. Plant
Scherer is a steam-electric generating plant located near Forsyth, Georgia. In
accordance with an operating agreement, Georgia Power acts as the Company's
agent with respect to the construction, operation, and maintenance of the unit.
The Company's pro rata share of expenses related to both plants is included
in the corresponding operating expense accounts in the Statements of Income.
At December 31, 1997, the Company's percentage ownership and its investment
in these jointly owned facilities were as follows:
Plant Scherer Plant
Unit No. 3 Daniel
(coal-fired) (coal-fired)
------------------------------
(in thousands)
Plant In Service $185,723(1) $222,230
Accumulated Depreciation $58,219 $108,176
Construction Work in Progress $282 $231
Nameplate Capacity (2)
(megawatts) 205 500
Ownership 25% 50%
-----------------------------------------------------------------
(1) Includes net plant acquisition adjustment.
(2) Total megawatt nameplate capacity:
Plant Scherer Unit No. 3: 818
Plant Daniel: 1,000
7. LONG-TERM POWER SALES AGREEMENTS
The Company and the other operating affiliates have long-term contractual
agreements for the sale of capacity and energy to certain non-affiliated
utilities located outside the system's service area. The unit power sales
agreements are firm and pertain to capacity related to specific generating
units. Because the energy is generally sold at cost under these agreements,
revenues from capacity sales primarily affect profitability. The capacity
II-168
NOTES (continued)
Gulf Power Company 1997 Annual Report
revenues from these sales were $24.9 million in 1997, $25.4 million in 1996, and
$25.9 million in 1995.
Unit power from specific generating plants of Southern Company is
currently being sold to Florida Power Corporation (FPC), Florida Power &
Light Company (FP&L), Jacksonville Electric Authority (JEA), and the City
of Tallahassee, Florida. Under these agreements, 211 megawatts of net
dependable capacity were sold by the Company during 1997, and sales will
remain at that level until the expiration of the contracts in 2010,
unless reduced by FPC, FP&L and JEA after 2000.
Capacity and energy sales to FP&L, the Company's largest single
customer, provided revenues of $25.4 million in 1997, $27.2 million in
1996, and $25.4 million in 1995, or 4.1 percent, 4.3 percent, and 4.1
percent of operating revenues, respectively.
8. INCOME TAXES
At December 31, 1997, the tax-related regulatory assets to be recovered
from customers were $26.6 million. These assets are attributable to tax
benefits flowed through to customers in prior years and to taxes applicable to
capitalized AFUDC. At December 31, 1997, the tax-related regulatory liabilities
to be credited to customers were $56.9 million. These 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:
1997 1996 1995
----------------------------------
(in thousands)
Total provision for income taxes:
Federal--
Currently payable $34,522 $31,022 $29,018
Deferred --current year 19,297 26,072 23,172
--reversal of
prior years (25,778) (24,780) (23,116)
------------------------------------------------------------------
28,041 32,314 29,074
------------------------------------------------------------------
State--
Currently payable 5,975 4,394 4,778
Deferred --current year 2,868 3,904 3,313
--reversal of
prior years (3,434) (3,039) (2,979)
------------------------------------------------------------------
5,409 5,259 5,112
------------------------------------------------------------------
Total 33,450 37,573 34,186
Less income taxes charged
(credited) to other income (1,584) (248) 121
------------------------------------------------------------------
Total income taxes charged
to operations $35,034 $37,821 $34,065
==================================================================
The tax effects of temporary differences between the carrying amounts of
assets and liabilities in the financial statements and their respective tax
bases, which give rise to deferred tax assets and liabilities, are as follows:
1997 1996
----------- -----------
(in thousands)
Deferred tax liabilities:
Accelerated depreciation $156,328 $151,664
Property basis differences 19,220 21,028
Other 14,242 17,622
-------------------------------------------------------------------
Total 189,790 190,314
-------------------------------------------------------------------
Deferred tax assets:
Federal effect of state deferred taxes 9,268 9,773
Postretirement benefits 6,976 5,767
Other 10,861 7,814
-------------------------------------------------------------------
Total 27,105 23,354
-------------------------------------------------------------------
Net deferred tax liabilities 162,685 166,960
Less current portion, net (3,617) 3,103
-------------------------------------------------------------------
Accumulated deferred income
taxes in the Balance Sheets $166,302 $163,857
===================================================================
Deferred investment tax credits are amortized over the life of the related
property with such amortization normally applied as a credit to reduce
depreciation and amortization in the Statements of Income. Credits amortized in
II-169
NOTES (continued)
Gulf Power Company 1997 Annual Report
this manner amounted to $2.2 million in 1997 and $2.3 million in 1996 and 1995.
At December 31, 1997, all investment tax credits available to reduce federal
income taxes payable had been utilized.
A reconciliation of the federal statutory income tax rate to the effective
income tax rate is as follows:
1997 1996 1995
--------- --------- ---------
Federal statutory rate 35% 35% 35%
State income tax,
net of federal deduction 4 4 4
Non-deductible book
depreciation 1 1 1
Difference in prior years'
deferred and current tax rate (1) (1) (3)
Other, net (4) (2) (2)
---------------------------------------------------------------
Effective income tax rate 35% 37% 35%
===============================================================
The Company and the other subsidiaries of Southern Company file a
consolidated federal tax return. Under a joint consolidated income tax
agreement, each subsidiary's current and deferred tax expense is computed on a
stand-alone basis. Tax benefits from losses of the parent company are allocated
to each subsidiary based on the ratio of taxable income to total consolidated
taxable income.
9. COMPANY OBLIGATED MANDATORILY
REDEEMABLE PREFERRED SECURITIES
In January 1997, Gulf Power Capital Trust I (Trust I), of which the Company owns
all of the common securities, issued $40 million of 7.625 percent mandatorily
redeemable preferred securities. Substantially all of the assets of Trust I are
$41 million aggregate principal amount of the Company's 7.625 percent junior
subordinated notes due December 31, 2036.
In January 1998, Gulf Power Capital Trust II (Trust II), of which the Company
also owns all of the common securities, issued $45 million of 7.0 percent
mandatorily redeemable preferred securities. Substantially all of the assets of
Trust II are $46 million aggregate principal amount of the Company's 7.0 percent
junior subordinated notes due December 31, 2037.
The Company considers that the mechanisms and obligations relating to the
preferred securities, taken together, constitute a full and unconditional
guarantee by the Company of payment obligations with respect to the preferred
securities of Gulf Power Capital Trust I and Trust II.
Gulf Power Capital Trust I and Trust II are subsidiaries of the Company, and
accordingly are consolidated in the Company's financial statements.
10. POLLUTION CONTROL OBLIGATIONS AND
OTHER LONG-TERM DEBT
Details of pollution control obligations and other long-term debt at December 31
are as follows:
1997 1996
--------------------------
(in thousands)
Obligations incurred in
connection with the sale by
public authorities of
tax-exempt pollution control
revenue bonds:
Collateralized
5.25% due 2006 $12,075 $12,075
8.25% due 2017 - 32,000
6.75% due 2022 - 8,930
Variable Rate due 2022
Remarketable daily 40,930 -
5.70% due 2023 7,875 7,875
5.80% due 2023 32,550 32,550
6.20% due 2023 13,000 13,000
6.30% due 2024 22,000 22,000
Variable Rate due 2024
Remarketable daily 20,000 20,000
5.50% due 2026 21,200 21,200
---------------------------------------------------------------
$169,630 $169,630
---------------------------------------------------------------
Other long-term debt:
5.2125% due 1996-1998 5,754 16,823
6.44% due 1994-1998 2,573 7,476
Variable Rate due 1999 13,500 13,500
Variable Rate due 1999 13,500 13,500
7.5% Junior Subordinated
Note due 2037 20,000 -
---------------------------------------------------------------
55,327 51,299
---------------------------------------------------------------
Total $224,957 $220,929
===============================================================
Pollution control obligations represent installment purchases of pollution
control facilities financed by funds derived from sales by public authorities of
revenue bonds. With respect to the collateralized pollution control revenue
II-170
NOTES (continued)
Gulf Power Company 1997 Annual Report
bonds, the Company has executed and delivered to trustees a like principal
amount of first mortgage bonds, or in the case of the $40.9 million issue a deed
of trust, as security for obligations under collateralized installment
agreements. The principal and interest on the first mortgage bonds will be
payable only in the event of default under the agreements.
The estimated annual maturities of other long-term debt are as follows:
$8.3 million in 1998 and $27 million in 1999.
11. SECURITIES DUE WITHIN ONE YEAR
A summary of the improvement fund requirement and scheduled maturities and
redemptions of long-term debt and preferred stock due within one year at
December 31 is as follows:
1997 1996
----------------------
(in thousands)
Bond improvement fund requirement $ 1,300 $ 1,550
Less: Portion to be satisfied by
certifying property additions 1,300 1,550
---------------------------------------------------------------
Cash sinking fund requirement - -
Maturities of first mortgage bonds 45,000 25,000
Current portion of other long-term
debt (Note 10) 8,327 15,972
Redemption of preferred stock - 24,500
---------------------------------------------------------------
Total $53,327 $65,472
===============================================================
The first mortgage bond improvement (sinking) fund requirement amounts to 1
percent of each outstanding series of bonds authenticated under the indenture
prior to January 1 of each year, other than those issued to collateralize
pollution control obligations. The requirement may be satisfied by depositing
cash, reacquiring bonds, or by pledging additional property equal to 1 and 2/3
times the requirement.
12. COMMON STOCK DIVIDEND RESTRICTIONS
The Company's first mortgage bond indenture contains various common stock
dividend restrictions which remain in effect as long as the bonds are
outstanding. At December 31, 1997, retained earnings of $127 million were
restricted against the payment of cash dividends on common stock under the terms
of the mortgage indenture.
The Company's charter previously limited cash dividends on common stock to 50
percent of net income available for such stock during a prior period of 12
months if the capitalization ratio is below 20 percent and to 75 percent of such
net income if such ratio is 20 percent or more but less than 25 percent. The
capitalization ratio is defined as the ratio of common stock equity to total
capitalization, including retained earnings, adjusted to reflect the payment of
the proposed dividend. At December 31, 1997, the ratio was 50.4 percent. These
restrictions were removed by a vote of preferred shareholders on December 10,
1997.
13. QUARTERLY FINANCIAL DATA (Unaudited)
Summarized quarterly financial data for 1997 and 1996 are as follows:
Net Income
After Dividends
Operating Operating on Preferred
Quarter Ended Revenues Income Stock
------------------------------------------------------------------
(in thousands)
March 31, 1997 $141,374 $20,212 $10,740
June 30, 1997 145,292 19,153 10,386
Sept. 30, 1997 193,710 34,750 27,484
Dec. 31, 1997 145,480 15,068 9,000
March 31, 1996 $154,921 $20,201 $11,258
June 30, 1996 153,821 21,565 12,581
Sept. 30, 1996 179,619 32,568 23,721
Dec. 31, 1996 146,004 19,458 10,285
------------------------------------------------------------------
The Company's business is influenced by seasonal weather conditions and the
timing of rate changes, among other factors.
II-171
II-172
II-173A
II-173B
II-173C