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10
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
X ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934 [FEE REQUIRED]
For the fiscal year ended December 31, 1995
OR
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934 [NO FEE REQUIRED]
For the transition period from ...........to.................
Commission file number 1-3198
IDAHO POWER COMPANY
(Exact name of registrant as specified in its charter)
IDAHO 82-0130980
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
1221 W. Idaho Street, Boise, Idaho 83702-5627
(Address of principal executive offices)(Zip Code)
Registrant's telephone number, including area code (208)388-2200
Securities registered pursuant to Section 12(b) of the Act:
Title of each class Name of each exchange on which registered
Common Stock ($2.50 par value) New York and Pacific
Securities registered pursuant to Section 12(g) of the Act:
Preferred Stock
(Title of Class)
Indicate by check mark whether the registrant (1) has 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 registrant was required to
file such reports), and (2) has 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 registrant's 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 nonaffiliates (January 31, 1996) $1,182,514,000
Number of shares of common stock outstanding at February 29, 1996
37,612,351
Documents Incorporated by Reference:
Part III, Item 10 Portions of the definitive proxy statement of
Item 11 the Registrant to be filed pursuant to
Item 12 Regulation 14A for the 1996 Annual Meeting of
Item 13 Shareowners to be held on May 1, 1996.
The exhibit index is located on page 69. This document contains
75 pages.
PART I
ITEM 1. BUSINESS
THE COMPANY
General -
Idaho Power Company (Company) is an electric public utility
incorporated under the laws of the state of Idaho in 1989 as
successor to a Maine corporation organized in 1915. The Company
is engaged in the generation, purchase, transmission,
distribution and sale of electric energy in an approximate 20,000-
square-mile area in southern Idaho, eastern Oregon and northern
Nevada, with an estimated population of 739,000 people. The
Company holds franchises in approximately 70 cities in Idaho and
10 cities in Oregon, and holds certificates from the respective
public utility regulatory authorities to serve all or a portion
of 28 counties in Idaho, 3 counties in Oregon and 1 county in
Nevada. The Company's results of operations, like those of
certain other utilities in the Northwest, can be significantly
affected by changing weather, precipitation and streamflow
conditions. Variations in energy usage by ultimate customers
occur from year to year, from season to season and from month to
month within a season, primarily as a result of weather
conditions. With the implementation of a power cost adjustment
mechanism (PCA) in the Idaho jurisdiction, which includes a major
portion of the operating expenses with the largest variation
potential (net power supply costs), the Company's future
operating results will be more dependent upon general regulatory,
economic, temperature conditions, and successful implementation
of Company strategic plans and less on precipitation and
streamflow conditions. As of December 31, 1995, the Company
supplied electric energy to 340,708 general business customers
and employed 1,626 people in its operations (1,522 full-time).
The Company operates 17 hydro power plants and shares ownership
in three coal-fired generating plants (see Item 2-"Properties").
The Company relies heavily on hydroelectric power for its
generating needs and is one of the nation's few investor-owned
utilities with a predominantly hydro base. The Company has
participated in the development of thermal generation in the
neighboring states of Wyoming, Oregon and Nevada using low-sulfur
coal from Wyoming and Utah.
For the twelve months ended December 31, 1995, total system
electric revenues from residential customers accounted for 35
percent of the Company's total operating revenues. Commercial
customers with less than 1,000 kW demand including street
lighting customers accounted for 19 percent, industrial customers
with 1,000 kW demand and over accounted for 20 percent and
irrigation customers accounted for 10 percent. Public utilities
and interchange arrangements accounted for 11 percent and other
operating revenues accounted for 5 percent.
The Company's principal commercial and industrial revenues are
from sales of electric power to customers involved in elemental
phosphorus production; food processing, preparation and freezing
plants; phosphate fertilizer production; electronics and general
manufacturing facilities; lumber; beet sugar refining; and
electric loads associated with the year-round recreational
business, such as lodges, condominiums, ski lifts and other
related facilities, including those at the Sun Valley resort
area.
The Company has four large special contract customers in its
Idaho retail jurisdiction - the Idaho National Engineering
Laboratory (INEL), the J. R. Simplot Company, FMC Corporation
(FMC) and Micron Technology, Inc. (Micron). The rates charged
these customers under their contracts are subject to the
jurisdiction of the Idaho Public Utilities Commission (IPUC). The
Company has contracts to supply up to 45 megawatts of capacity
and energy to the INEL in eastern Idaho, up to 38 megawatts of
capacity and energy to the J. R. Simplot Company for its chemical
fertilizer operations plant near Pocatello, Idaho and 60
megawatts (this amount escalates to 100 megawatts at July 1997)
of capacity and energy to Micron located in Boise. The contracts
for J.R. Simplot and Micron expire in different years but are
automatically renewed until one party gives notice of final
termination. The contract for INEL does expire in 1996 and the
Company will be negotiating a new contract prior to that time.
Since 1948, the Company has supplied capacity and energy to FMC
for its elemental phosphorus production plant near Pocatello,
Idaho. Under an agreement effective on January 1, 1974, the
maximum amount of power that FMC may schedule is 250 megawatts.
The agreement is subject to renewal by FMC every two years as to
one-fourth of the power deliveries and contains annual minimum
payment guarantees giving consideration to FMC's ability to
decrease its electric demands during periods in which the Company
may request reductions specified in the agreement. Revenues from
FMC were approximately $34.5 million for energy supplied during
the twelve months ended December 31, 1995.
Competition -
Competition is increasing in the electric utility industry, due
to a variety of developments including the National Energy Policy
Act of 1992, FERC Rulemakings, state initiatives, customer
demands, etc. In response to increasing competition, the Company
maintains an active strategic planning process. The goal of this
process is to anticipate and fully integrate into Company
operations any legislative, regulatory, environmental,
competitive, or technological changes. With its low average
energy production costs, the Company is well-positioned to enter
a more competitive environment and is taking action to preserve
its low-cost competitive advantage. (see Part II, Item 7.
Management's Discussion and Analysis of Financial Condition and
Results of Operations - Competition and Strategic Planning.)
With its predominantly hydro base and low-cost thermal plants,
the Company is one of the lowest cost producers of electric
energy among the nation's investor-owned utilities. Through its
interconnections with Bonneville Power Administration (BPA) and
other utilities, the Company has access to all the major electric
systems in the West.
Some industrial and large commercial customers have the ability
to own and operate facilities to generate their own electric
energy and if such facilities are qualifying facilities, can
require the displaced electric utility to purchase the output of
such facilities at a state regulatory commission established
"avoided cost" rate (see "Rates"). The Company's rates for its
industrial customers (1,000 kW and over), excluding special
contracts, average approximately 2.9 cents per kilowatt hour (see
"Power Supply"). Some of these customers are converting waste
heat to electricity for sale to the Company while purchasing
their entire power needs at the Company's lower rates. The
Company's rates for its commercial customers (under 1,000 kW)
average approximately 4.0 cents per kilowatt hour.
The legislatures and/or the regulatory commissions in several
states have considered or are considering "retail wheeling."
Retail wheeling means the movement of electric energy produced by
another entity over an electric utility's transmission and
distribution system, to a retail customer in what was the
utility's service territory. A requirement to transmit directly
to retail customers would permit retail customers to purchase
electric capacity and energy from the electric utility in the
service area they are located or from any other electric utility
or independent power supplier.
The Idaho Legislature has not yet addressed retail wheeling but
the IPUC has started an issues dialogue process and has
established workshops for discussing retail wheeling issues among
the affected parties. The Company believes with its low-cost
energy production it is well-positioned to compete in a retail
wheeling environment if retail wheeling is adopted by one or more
of the Western states (see "Regulation").
Subsidiaries -
The Company has five wholly-owned subsidiary companies: Ida-West
Energy Company (Ida-West), Idaho Energy Resources Co. (IERCo),
Idaho Utility Products Company (IUPCo), IDACORP, INC., and
Stellar Dynamics.
Ida-West was formed in 1989 to participate through partnership
interests in cogeneration and small power production (CSPP)
projects. Ida-West owns, through various partnerships, 50 percent
of five Idaho hydroelectric projects with a total generating
capacity of approximately 34 megawatts (MW). Third parties
unaffiliated with Ida-West own the remaining 50 percent of these
projects, thus satisfying the "qualifying facility" status under
Public Utility Regulatory Policy Act of 1978 (PURPA) guidelines.
The partnerships have obtained project financing (non-recourse to
the Company) for each of these facilities. Power purchased from
these facilities amounted to approximately $8.7 million in 1995.
To date, all power sales made by Ida-West have been to the
Company.
The Company has invested $20 million in Ida-West. Ida-West
continues to actively seek to develop new projects. (see Part II,
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations - Subsidiaries.)
IERCo has been in operation since 1974. Its primary purpose is to
participate as a joint venturer in the Bridger Coal Company,
which operates the mine supplying coal to the Jim Bridger plant
near Rock Springs, Wyoming (see "Fuel"). As of December 31, 1995,
the Company's total investment in IERCo was $5.6 million.
IDACORP, INC was organized in 1986 to pursue a non-regulated
diversification program. At the end of 1995 IDACORP was
participating in three affordable housing programs which provide
a return primarily by reducing federal income taxes through tax
credits and tax depreciation benefits. IUPCo was formed in 1983
to develop and market products to the utility industry. As of
December 31, 1995, the combined total investment in these
subsidiaries was $3.3 million.
Stellar Dynamics was formed in 1995 to commercialize the
Company's extensive expertise in control technology for electric
substations and power plants. Today, the market focus lies in the
integration of complex control and automation systems for both
the electric utility sector and industrial applications. Stellar
Dynamics also provides design and engineering for complete
electric substations. The geographic market for Stellar Dynamics
is mainly in the western U.S. with some emphasis in the remaining
U.S., Canada and abroad. The Company capitalized Stellar Dynamics
in January of 1996.
Research and Development and Renewable Energy Sources -
During 1995, the Company spent approximately $1.7 million on
research and development of which $1.5 million was through the
Company's membership in Electric Power Research Institute (EPRI).
EPRI's mission is to discover, develop and deliver advances in
science and technology. Some of the projects benefits to the
Company include: electrification technologies, power quality,
electric transportation systems, EMF assessment/risk management
and air quality issues. The Company also has an internal research
and development effort called the Emerging Technology (ET)
Program. The ET program was established to maintain an active and
coordinated response to new technology of interest to the
Company.
In 1992, the Company joined Southern California Edison, the U.S.
Department of Energy and others in retrofitting an existing 10-
megawatt solar thermal experimental power plant now called Solar
Two near Barstow, California. The Company will have contributed
$630,500 by the end of 1998 and the EPRI will contribute an
additional $630,500 of matching funds, bringing the Company's
credited contribution to approximately $1.3 million. The main
benefit the Company will receive by participating in this project
is valuable experience and knowledge in solar plant design,
construction and operation.
The Company offers a Photovoltaic Service Tariff (PST) for basic
electric service for small loads at remote sites as an
alternative to either line extensions for grid service or the use
of on-site, fossil-fuel generators. Under the PST, the customer
pays a monthly fee to receive electric service from a solar PV
system designed, installed, owned, and maintained by Idaho Power.
The program, which the Company launched in January 1993, is a
pilot offering with a $5,000,000 program limit and a $50,000
limit for individual systems. To date, Idaho Power has installed
30 solar photovoltaic (PV) systems. All of these systems are
operating as designed.
In 1994, the U.S. Air Force contracted with Idaho Power to
design, build, and maintain one of the nation's largest hybrid
solar-powered PV systems. The $1.2 million project, completed in
February 1995, provides electricity to a remote Mountain Home AFB
radar training installation near Grasmere, Idaho. Under optimal
solar conditions, the PV system produces a peak capacity of
80 kW, reducing both the need for combustion generators and the
emissions they produce. Under the terms of the contract, the
federal government owns the system and pays the Company a monthly
maintenance fee.
Through these programs, Idaho Power has gained considerable
experience in the design and maintenance of solar PV energy
systems. As a result, the Company has gained international
recognition as an industry leader in solar PV technology, and was
selected to organize and jointly host an international solar PV
conference which was held in Sun Valley, Idaho in September 1995.
The Company is studying the possible formation of a new, non-
regulated energy services company that would partner with
interested electric utilities to provide energy services to
remote locations within their service territories. This company
would work on behalf of the utilities to offer solar PV energy
systems at the lowest possible cost to the consumer. While the
domestic utility market is promising in itself, Idaho Power is
also pursuing international opportunities for its renewable
energy expertise.
Energy Efficiency -
The Company continues to promote the efficient use of electrical
energy. The Company supported legislation in Idaho that
established energy-efficient building codes for new home
construction and continues to support the adoption of even more
stringent energy codes by local government jurisdictions. In
1995, the Company expended $6.4 million on its various energy-
efficiency programs.
POWER SUPPLY
The Company is a dual-peaking system, with the larger energy peak
generally occurring in the summer. This complements the winter
peaking utilities which predominate in the Pacific Northwest.
Even though its significant hydroelectric generation can operate
to meet demand peaks, seasonal energy requirements are important
to the Company because its seasonal energy capability is
determined in part by the availability of water. In 1994, below
normal precipitation created drought conditions reducing
reservoir storage. In 1993 and 1995 however, the Company's
service territory experienced above average water years. The
system peak demand for 1995 was 2,393 megawatts set on July 28,
1995. Peak demand for 1994 and 1993 were 2,392 and 2,154
megawatts respectively.
The following table sets forth the total energy sources of the
Company for the last three years:
Total Energy Sources
(000's of MWH)
1995 % 1994 % 1993 %
Generation - net station output -
Hydro 9,277.2 58 6,213.2 40 8,361.7 52
Coal-fired 4,591.9 29 7,221.8 46 6,485.5 40
Purchased and
interchange 2,155.9 13 2,287.0 14 1,273.8 8
Total 16,025.0 100 15,722.0 100 16,121.0 100
In a normal water year the hydro system contributes approximately
57 percent, thermal generation accounts for 34 percent and
purchased power and other interchanges contributes the remaining
9 percent of total system requirements. Although it is too early
to predict with certainty what hydroelectric conditions will be
during 1996, preliminary reports indicate the mountain snowpack
is above normal for this time of year and the carryover reservoir
storage throughout the Snake River Basin is above average. The
Company expects to meet projected energy loads during the coming
year by utilizing its hydro and coal-fired facilities and
strategic geographic location - which provides opportunities to
purchase, sell, exchange and transmit energy.
Purchased power expenses fluctuated during the three-year period
reflecting necessity purchases from neighboring utilities during
the 1994 drought. Purchased power expenses were lower in 1995
with the return to more normal hydro conditions tempered somewhat
by economy purchases made while the market prices for off-system
sales were soft.
The Company periodically updates its load and resource
projections and now expects total Company energy requirements
over the next 10 years to grow at an annual rate of 0.8 percent.
The Company's generating facilities are interconnected through
its integrated transmission system and are operated on a
coordinated basis to achieve maximum load-carrying capability and
reliability. The transmission system of the Company is directly
interconnected with the transmission systems of the BPA, The
Washington Water Power Company, PacifiCorp, The Montana Power
Company and Sierra Pacific Power Company (SPPCo). Such
interconnections, coupled with transmission line capacity made
available under agreements with certain of the above utilities,
permit the advantageous interchange, purchase and sale of power
among most of the electric systems in the West. The Company is a
member of the Intercompany Pool, the Western Systems Coordinating
Council, the Western Systems Power Pool, the Northwest Power
Pool, the Western Regional Transmission Association and the
Northwest Regional Transmission Association.
Increasing competitiveness in the electric power marketplace, the
potential ability of retail customers to choose their electric
provider and the potential for deregulation of the electric power
industry, all indicate a need for the Company to adjust its
resource acquisition policy toward a greater emphasis on resource
marketability. In order to avoid burdening the Company and its
customers with unnecessary future power supply costs and higher
rates, the Company has adopted a policy of acquiring all new
resources as close as possible to the actual time of need and
selecting the lowest cost resources meeting all of the Company's
requirements. In practice, this policy will result in the
purchase of power from others through the marketplace whenever
purchases are the lowest cost resources, and new investment in
resource ownership by the Company only when a Company-owned
resource would be cost effective in the market.
In December 1993, the Company filed with the IPUC for permission
to approve lower published prices for new CSPP contracts. In
response to the Company's filing, on January 31, 1995 the IPUC
issued an order approving lower published CSPP rates. (see Rates -
Idaho Jurisdiction and Part II, Item 7. Management's Discussion
and Analysis of Financial Condition and Results of Operations -
Regulatory Issues.)
New Projects -
Capitalizing on the Company's strategic location between the
Intermountain West and the Pacific Northwest, the Company is
considering the construction and operation of a new transmission
line that could serve as a major path for regional transfers of
power between the Northwest and desert Southwest. The Southwest
Intertie Project (SWIP) is a proposed 500-mile, 500-kV
transmission line that would interconnect the Company's system
with utilities in the Southwest. In December 1994, the US Bureau
of Land Management (BLM) issued a favorable record of decision on
the Company's environmental impact statement and granted the
project a right-of-way across public lands in Idaho, Nevada and
Utah. The utility and BLM are working on a detailed site-specific
construction, operation and maintenance plan aimed at mitigating
the environmental impact of the project. The Company intends to
retain up to a 20 percent ownership in the 1,200 megawatt line.
The Company sent participation packages to interested parties and
received capacity requests from these groups during the fourth
quarter of 1995. Ownership allocation has been completed among
the six interested parties and negotiations are in process for
the execution of the Memorandum of Agreement (MOA). At the time
of execution of the MOA, the Company is requiring each party to
pay its share of the approximately $8.5 million expended for
environmental permitting, right-of-way acquisition, and related
development activities. The SWIP owners will then form an
Executive Committee with voting rights proportional to their
share of the project. The Executive Committee will oversee
development activities for the SWIP and related projects.
The Company is positioning SWIP as an open-access transmission
opportunity for participants, in line with the Notice of Proposed
Rulemaking (NOPR) issued by the Federal Energy Regulatory
Commission (FERC).
The following tables show how the Company expects to meet its
forecast energy and peak demand requirements through 2000 from
system generation and contracted resources. Because of its
reliance upon hydroelectric generation, which varies according to
streamflows, the Company's generating system is more energy
constrained than capacity limited. Seasonal exchanges of winter-
for-summer power are included among the contracted resources to
maximize the firm load carrying capability. Exchanges are
currently made with The Montana Power Company under a 10-year
contract signed in 1987 and with Seattle City Light under an
extended contract that expires in 2003.
Summer Peak Capability (MW) (a)
1996 1997 1998 1999 2000
Generation capability 2,681 2,681 2,681 2,681 2,681
Less net peak load 2,318 2,390 2,467 2,476 2,489
Plus contract power (b) 286 305 305 305 305
Peak capability margin 649 596 519 510 497
Percent capability margin (c) 28.0% 24.9% 21.0% 20.6%
20.0%
(a) Based upon median hydro conditions.
(b) Sum of exchange and CSPP contracts.
(c) Capability margin divided by the net peak load.
Annual Energy Capability
(000's of MWH)(a)
1996 1997 1998 1999 2000
Generation capability 15,246 15,187 15,476 15,530 15,726
Contracts:
Cogeneration and small
power production 696 807 807 807 807
Annual firm load (15,532) (15,635) (16,153) (16,148) (16,083)
Energy capability margin 410 359 130 189 450
Percent (b) 2.6% 2.3% 0.8% 1.2% 2.8%
(a) Forecast based upon average of 67 historical water
conditions.
(b) Energy capability margin divided by the generating
capability. These projections have declined due to the
Company's Bulk Power Initiative with more assumed firm sales
replacing surplus sales and CSPP projects not coming on line.
During the 1996-2000 period, the Company plans to provide all the
energy required to serve its firm load requirements during
periods of heavy demand, reduced hydrogeneration caused by below
normal streamflow conditions, or unscheduled outages of
generating units by utilizing its hydroelectric and coal-fired
generating units and through purchases of power from neighboring
utilities or marketing entities.
CSPP Purchases -
As a result of the enactment of the PURPA and the adoption of
avoided cost standards by the IPUC, the Company has entered into
contracts for the purchase of energy from private developers.
Because the Company's service territory encompasses substantial
irrigation canal development, forest products production
facilities, mountain streams, and food processing facilities,
considerable amounts of energy are available from these sources.
Such energy comes from hydro power producers who own and operate
small plants and from cogenerators converting waste heat or steam
from industrial processes into electricity. The estimated
annualized cost for the 65 CSPP projects on-line as of December
31, 1995, is currently $45.2 million. During 1995, the Company
purchased 654.2 million kilowatt-hours of power from these
private developers at a blended price of 5.8 cents per kilowatt-
hour (see Rates).
Firm Wholesale Power Sales -
The Company has firm wholesale power sales contracts with SPPCo,
Portland General Electric Company (PGE), The Montana Power
Company (MPC), the City of Weiser, Idaho, two entities in the
state of Utah, one in the state of California and one in the
state of Oregon. These contracts are for various amounts of
energy and range from 7 to 100 average megawatts and are of
various lengths that are presently scheduled to expire between
1996 and 2009. The Company has contracts with both MPC and PGE
that expire during 1996. These contracts are for various amounts
of power depending on the time of year and range from 25 to 100
average megawatts. The Company is actively marketing this power
to other entities as it becomes available.
Transmission Services
The Company has long had an informal open-access transmission
policy and is experienced in providing reliable, high quality,
economical transmission service. The Company provides various
firm and nonfirm wheeling services for several surrounding
utilities. In November 1995, the Company filed open-access
tariffs for Point-to-Point and Network transmission service with
the FERC. The Company requested and received permission to
implement these tariffs beginning February 1, 1996.
The substance of these tariffs is to offer the same quality and
character of transmission services to anyone seeking it as the
Company utilizes in its own operation. The FERC set the proposed
rates for service under the tariffs for hearing, and the Company
may provide service at these proposed rates subject to refund.
During 1995, the Company reorganized its Power Supply Department
into power supply (generation) and power delivery (transmission)
business units to enhance the Company's ability to compete in the
wholesale electric power market and to comply with the "Standards
of Conduct" proposed by the FERC in their recent Notice of
Proposed Rulemaking.
The Company's system lies between and is interconnected to the
winter-peaking northern and summer-peaking southern regions of
the western interconnected power system. This position is
advantageous both in providing transmission service and reaching
a broad power sales market. The Company is a member of both the
Western Regional Transmission Association and the Northwest
Regional Transmission Association. These associations will help
facilitate transmission access and planning throughout the power
system.
FUEL
The Company, through Idaho Energy Resources Co., owns a one-third
interest in the Bridger Coal Company which owns the Jim Bridger
coal mine that supplies coal to the Jim Bridger generating plant
in Wyoming. The mine, located near the Jim Bridger plant,
operates under a long-term sales agreement and provides for
delivery of coal over a 51-year period that began in 1974. The
original contract of 41 years was extended for 10 years on
January 1, 1996. (see Item 2 "Properties"). The Jim Bridger Coal
Mine has sufficient reserves to provide coal deliveries pursuant
to the sales agreement. The average cost to the Company per ton
of coal burned at the Jim Bridger plant, the largest thermal
station on the Company's system, for the last three years is as
follows: 1993 - $20.99; 1994 - $19.52 and 1995 - $20.36. The
Company also has a coal supply contract providing for annual
deliveries of coal through 2005 from the Black Butte Coal
Company's Leucite Hills mine adjacent to the Jim Bridger project.
This contract supplements the Bridger Coal Company deliveries and
provides another coal supply to operate the Jim Bridger plant.
The Jim Bridger plant's rail load-in facility and unit coal train
allows the plant to take advantage of potentially lower-cost coal
from outside mines for tonnage requirements above established
contract minimums.
PGE, with whom the Company is a 10 percent participant in the
ownership and operation of the Boardman plant, has a flexible
contract with AMAX Coal Company for delivery of low sulfur coal
from its mines near Gillette, Wyoming, to Boardman Unit No. 1.
Under this contract, PGE has the option to purchase 750,000 tons
of coal annually through 1999. This agreement enables PGE and the
Company to take advantage of lower cost spot market coal for some
or all of the Boardman plant's requirements.
SPPCo, with whom the Company is a joint (50/50) participant in
the ownership and operation of the North Valmy Steam Electric
Generating plant (Valmy plant), entered into a 22-year coal
contract that began in July of 1981 with Southern Utah Fuel
Company, a subsidiary of Coastal States Energy Corporation, for
the delivery of up to 17.5 million tons of low-sulfur coal from a
mine near Salina, Utah, for Valmy Unit No. 1.
With the commercial operation of Valmy Unit No. 2 in May 1985, an
additional coal source was needed to assure an adequate supply
for both units at the Valmy plant. Accordingly, in 1986 the
Company and SPPCo signed a long-term coal supply agreement with
the Black Butte Coal Company. This contract provides for Black
Butte to supply coal to the Valmy project under a flexible
delivery schedule that allows for variations in the number of
tons to be delivered ranging from a minimum of 200,000 tons per
year to a maximum of 1,150,000 tons per year. This flexibility
will accommodate fluctuations in energy demands, hydroelectric
generating conditions and purchases of energy from CSPP
facilities.
WATER RIGHTS
The Company, except as otherwise stated herein, has valid water
rights, unlimited as to time, to the waters used in its
generating stations, which were obtained under applicable
provisions of state law. Such rights, however, are subject to
prior rights and, with respect to license provisions of certain
hydroelectric facilities and water licenses, are subject to
future upstream diversion of water for irrigation and other
consumptive use.
Over time, increased irrigation and other consumptive diversions
on the Snake River have resulted in some reduction in the
streamflows available for the Company's hydroelectric generating
facilities. In this regard, the Company has pursued a course of
action to determine and protect its water rights and their
priority consistent with the settlement agreements negotiated
with the state of Idaho signed on October 25, 1984. In 1987,
Congress passed and the President signed into law House Bill 519
which permitted implementation of the agreements and provided
that the FERC would accept the settlement agreements and that the
settlement was consistent with the terms of hydroelectric
licenses and was prudent for the purpose of determining rates
under Section 205 of the Federal Power Act during the remaining
term of certain project licenses on the Snake River.
In 1987, the Idaho Department of Water Resources filed a petition
in state district court commencing the Snake River Basin
Adjudication. This proceeding was initiated pursuant to state
statute and a determination by the Idaho Legislature that the
effective management of the Snake River basin required a
comprehensive determination of the nature, extent and priority of
all water users. The adjudication is still in its early stages,
and the process will likely continue past the turn of the
century. The Company has filed claims to its water rights within
the basin and is participating in the adjudication to insure that
its operations and water rights are not adversely impacted. The
Company does not anticipate any modification of its water rights
as a result of the adjudication process.
REGULATION
The Company is not in direct competition with any electric public
utility company or municipality within its service territory. The
Company is under the regulatory jurisdiction (as to rates,
service, accounting and other general matters of utility
operation) of the FERC, the IPUC, the Oregon Public Utilities
Commission (OPUC) and the Public Service Commission of Nevada.
The Company is also under the regulatory jurisdiction of the
IPUC, OPUC and the Public Service Commission of Wyoming as to the
issuance of securities. The Company is subject to the provisions
of the Federal Power Act as a "licensee" and "public utility" as
therein defined. The Company's retail rates are established under
the jurisdiction of the state regulatory agencies and its
wholesale and transmission rates are regulated by the FERC (see
"Rates"). Pursuant to the requirements of Section 210 of the
PURPA, the state regulatory agencies have each issued orders and
rules regulating the Company's purchase of power from CSPP
facilities.
As a licensee under the Federal Power Act, the Company and its
licensed hydroelectric projects are subject to the provisions of
Part I of the Act. All licenses are subject to conditions set
forth in the Act and regulations of the FERC thereunder,
including, but not limited to, provisions relating to
condemnation of a project upon payment of just compensation,
amortization of project investment from excess project earnings,
possible takeover of a project after expiration of its license
upon payment of net investment, severance damages, and other
matters.
The state of Oregon has a Hydroelectric Act providing for
licensing of hydroelectric projects in that state. The Company's
Brownlee, Oxbow and Hells Canyon facilities are on the Snake
River where it forms the boundary between Idaho and Oregon and
occupy land located in both states. These facilities are subject,
with respect to project property located in Oregon, to such
provisions of the Oregon Hydroelectric Act. The Company has
obtained Oregon licenses for these facilities and these licenses
are not in conflict with the Federal Power Act or the Company's
FERC license (see Item 2. Properties).
ENVIRONMENTAL REGULATION
Environmental controls at the federal, state, regional and local
levels are having a continuing impact on the Company's operations
due to the cost of installation and operation of equipment
required for compliance with such controls and the modification
of system operations to accommodate such regulation.
Based upon the requirements of present environmental laws and
regulations, the Company estimates its capital expenditures
(excluding allowance for funds used during construction) for
environmental matters for 1996 and during the period 1997-2000
will total approximately $0.6 million and $24.9 million,
respectively. Mitigation of environmental concerns due to
relicensing of hydro facilities will be a major portion of these
expenditures. The Company also anticipates spending approximately
$24 million a year in operating expenses for environmental
facilities during the 1996-2000 period. However, to the extent
regulations under federal and state environmental protection
laws, as well as the laws themselves, are changed, costs for
compliance with such laws and regulations in connection with the
Company's existing facilities and facilities under construction
are subject to change in an amount not determinable.
Air -
The Company continues to monitor Clean Air Act legislation and
its effects upon the Company and its ratepayers. The Company's
coal-fired plants in Nevada and Oregon already meet the federal
emission rate standards for sulfur dioxide (SO2) and the
Company's coal-fired plant in Wyoming meets that state's even
more stringent SO2 regulations. The Company anticipates no
material adverse effect upon its operations. The Company has
entered into a joint arrangement with PacifiCorp and Black Hills
Corporation under which certain of these companies generating
units have been accepted by the Environmental Protection Agency
as "Substitution" units for the Baldwin #2 unit owned by Illinois
Power Company. In exchange for Illinois Power naming units at the
Jim Bridger Station as "Substitution" units for Baldwin #2, the
Company sold Illinois Power a portion of the Phase I SO2
Allowances it received by having its share of the Jim Bridger
units accepted as Phase I "Substitution" units.
Water -
The Company has received National Pollutant Discharge Elimination
System Permits, as required under the Federal Water Pollution
Control Act Amendments of 1972, for the discharge of effluents
from its hydroelectric generating plants.
The state of Oregon Department of Environmental Quality
determined that the flow of water over large dams on the Columbia
and Snake Rivers could result in the supersaturation of the water
with dissolved nitrogen possibly resulting in damage to the fish
population. The Company has obtained a permit from the Oregon
Department of Environmental Quality to operate the Brownlee,
Oxbow and Hells Canyon Dams in accordance with the water quality
program of the state of Oregon.
At the Company's American Falls hydroelectric generating plant,
the Company has agreed to meet certain dissolved oxygen
standards. The Company signed amendments to the agreements
relating to the operation of the American Falls Dam and the
location of water quality monitoring facilities to provide more
accurate and reliable water quality measurements necessary to
maintain water quality standards during the May 15 to October 15
period each year downstream from the Company's plant.
The Company has also installed aeration equipment, water quality
monitors and data processing equipment as part of the Cascade
hydroelectric project to provide accurate water quality data and
increase dissolved oxygen levels as necessary to maintain water
quality standards on the Payette River.
The Company owns and finances the operation of anadromous fish
hatcheries and related facilities to mitigate the effects of its
hydroelectric dams on fish populations. In connection with its
fish facilities, the Company sponsors ongoing programs for the
control of fish disease and improvement of fish production. The
Company's anadromous fish facilities at Hells Canyon, Oxbow,
Rapid River, Pahsimeroi and Niagara Springs continue to be
operated under agreements with the Idaho Department of Fish and
Game. In 1995, the investment in these facilities was $12.1
million and the operation of these facilities pursuant to the
FERC License 1971 cost approximately $2.1 million annually.
Endangered Species -
The Company continues to review and analyze the various effects
upon its operations of the listing as threatened or endangered of
several species of salmon and Snake River mollusks. The Company
is cooperating with various governmental agencies to resolve
these issues. (see Part II, Item 7. Management's Discussion and
Analysis of Financial Condition and Results of Operation -
Environmental Issues.)
Hazardous/Toxic Wastes and Substances -
Under the Toxic Substances Control Act (TSCA), the Environmental
Protection Agency (EPA) has adopted regulations governing the
use, storage, inspection and disposal of electrical equipment
that contain polychlorinated biphenyls (PCBs). The regulations
permit the continued use and servicing of certain electrical
equipment (including transformers and capacitors) that contain
PCBs. The Company continues to meet all federal requirements of
TSCA for the continued use of equipment containing PCBs. The
Company has a program to make the 200-plus substations on its
system non-PCB. While the Company's use of equipment containing
PCBs falls well within the federal standards, the Company has
voluntarily decided to virtually eliminate these compounds from
the substation sites. This program will save costs associated
with the long-term monitoring and testing of substation equipment
and grounds for PCB contamination as well as being good for the
environment today. Total Company costs for the disposal of PCB's
from the Company's system were $0.6 million, $1.3 million and
$0.4 million for 1993, 1994 and 1995 respectively.
Electric and Magnetic Fields (EMF) -
While scientific research has yet to establish any conclusive
link between EMF and human health, the possibility has caused
public concern in the United States and abroad. Electric and
magnetic fields are found wherever there is electric current,
whether the source is a high-voltage transmission line or the
simplest of electrical household appliances. Concerns over
possible health effects have prompted regulatory efforts in
several states to limit human exposure to EMF. Depending on what
researchers ultimately discover and what regulations may be
deemed necessary, it is possible that this issue could affect a
number of industries, including electric utilities. However, at
this time it is difficult to estimate what impacts, if any, the
EMF issue could have on the Company and its operations.
RATES
Idaho Jurisdiction -
Since 1993, the Company's Power Cost Adjustment (PCA) mechanism
has allowed for it to collect, or to refund, a portion of the
differences between actual net power supply costs and those
allowed in the Company's Idaho base rates. Rates are adjusted
each May based on forecasted costs for the upcoming May-April
period. Deviations from forecasted costs are deferred with
interest and trued up the following year. With the IPUC's revenue
requirement order issued on January 31, 1995, the PCA mechanism
increased to a 90 percent recovery level from its original 60
percent. The Company filed its 1995 PCA application with the IPUC
on April 15, 1995 requesting a decrease in PCA rates for the
Idaho jurisdiction. The decrease (in effect from May 16, 1995
through May 15, 1996) was approximately $8.2 million or 1.9
percent including last year's true-up. However, PCA rates are
still in excess of base rates. At December 31, 1995, the Company
had recorded $1.0 million less in power supply costs than
projected in the 1995 forecast. The Company has deferred this
cumulative amount and will include it as a reduction in the 1996
PCA true-up.
On June 30, 1994, Idaho Power filed an application with the IPUC
to increase rates in its Idaho jurisdiction. The Company based
its application on calendar year 1993, using a thirteen-month
average rate base annualized for its new Swan Falls production
project and a year-end capitalization structure. In its
application, the Company requested $37.1 million in general rate
relief, representing a 9.09 percent increase in rates, a 12.50
percent return on equity, and a 9.88 percent overall rate of
return. On January 31, 1995, the Company received IPUC Order No.
25880, which authorized $17.2 million in general rate relief,
representing a 4.2 percent overall increase in Idaho retail
rates. The relief was based on an 11.0 percent allowed return on
equity and an overall rate of return of 9.2 percent. The increase
in Idaho retail rates went into effect on February 1, 1995. IPUC
Order No. 25880 also allowed Idaho Power to realize its overall
rate structure to more closely price according to the cost to
serve different customer classes.
On May 24, 1995, Idaho Power filed another application with the
IPUC to increase rates in its Idaho jurisdiction. In August 1995,
the IPUC issued an order authorizing the Company to increase its
Idaho retail rates on an annual basis by $3.8 million (0.9
percent). This increase was uniform to all customer classes, as
well as to special contract customers. The Company originally
applied for a $6.3 million (1.5 percent) increase to recover
capital costs and related expenses associated with the
construction of a new 43.5 megawatt (MW) power plant at its Twin
Falls hydro facility, along with additional plant investments at
the Swan Falls hydro facility since the filing of its last
general rate case. The major issue in this case was whether the
reduced power supply costs resulting from the inclusion of the
Twin Falls hydro expansion would be recognized explicitly through
a reduction in base energy rates or implicitly through the PCA.
The Company reached a compromise with the IPUC staff on the
overall revenue requirement and agreed to recognize benefits up
front in base rates, instead of flowing the benefits through the
PCA. As a result, the Company's original $6.3 million request was
reduced by $1.9 million. The effect on projected Company earnings
is only 10 percent of this amount ($190,000), since all but 10
percent of the power supply cost reduction would have been passed
through to Idaho customers in the next PCA adjustment. The IPUC
action enabled the Company to begin recovering the capital costs
of a plant addition within weeks of the plant becoming
operational.
On August 3, 1995, the Company filed a proposal with the IPUC to
defer and amortize costs associated with its internal
transformation process, to accelerate amortization of regulatory
liabilities associated with accumulated deferred investment tax
credits (ADITCs) under certain conditions and to hold base rates
stable through 1998. The IPUC approved a settlement agreement
confirming the proposal, which allows the Company to accelerate
the amortization of the regulatory liabilities associated with
ADITCs whenever the Company's year-end return on equity falls
below 11.5 percent. In addition, the order allows the Company to
defer certain costs associated with its corporate reorganization
as regulatory assets and amortize them over a 10-year period.
The terms and conditions of the Order will remain in effect
through 1999. Under the Order, when the Company's actual earnings
in a given year exceed an 11.75 percent return on year-end common
equity, the Company will refund 50 percent of the excess through
its next PCA adjustment.
Other important points in the Order are: (1) the Company may
accelerate a maximum of $30 million of regulatory liabilities
associated with ADITCs over the five-year period; (2) the Company
will not be allowed to increase its Idaho general rates prior to
January 1, 2000, except under special conditions as defined in
the Settlement Agreement; and (3) Idaho Power agrees that its
quality of service will not decline as a result of corporate
reorganization. The proposed accounting treatment of deferred
investment tax credits has been submitted to the Internal Revenue
Service for approval. On November 22, 1995, the Idaho State Tax
Commission approved the accounting treatment for the Idaho
ADITCs. No accelerated ADITC was required and thus none was
utilized in 1995.
In December 1993, the Company filed with the IPUC for permission
to approve lower published prices for new CSPP contracts. In
response to the Company's filing, the IPUC issued an order on
January 31, 1995, approving lower published CSPP rates. In
addition, the IPUC determined that negotiated rates for future
CSPP projects larger than 1 MW should be tied more closely to
values determined in the Company's integrated resource planning
(IRP) process.
Oregon Jurisdiction -
In response to the Company's April 1995 application, the OPUC
granted $1.5 million in drought-related rate relief. The OPUC
Order allows recovery of the $1.5 million through the continued
application of an existing increase authorized in July 1993 (for
1992 drought relief). The rate increase will remain in effect for
approximately 34 months beginning in July 1995. The Company had
deferred, with interest, increased power supply costs between May
1994 and December 31, 1994.
In May 1995, Idaho Power filed an application with the OPUC
seeking general rate relief of approximately $3.4 million, or a
16.65 percent increase. The Company later negotiated a Settlement
Stipulation with the OPUC staff, the Company's Oregon industrial
customers, and the Citizens Utility Board of Oregon. The
settlement grants Idaho Power a $1.3 million general rate
increase for its Oregon retail customers. The OPUC settlement
agreement became effective December 5, 1995
Other Jurisdictions -
In 1995, the Company did not file any applications for rate
relief before the FERC or in its Nevada retail jurisdiction.
CONSTRUCTION PROGRAM
The Company's construction program for the 1996-2000 period
(excluding allowances for funds used during construction) is
presently estimated to require cash funds of approximately $417.7
million as follows:
1996 1997-2000(a)
(Millions of Dollars)
Generating Facilities:
Hydro $ 5.7 $ 45.2
Thermal 9.1 34.0
Total generating facilities 14.8 79.2
Transmission lines and substations 12.8 47.8
Distribution lines and substations 42.4 146.4
General 20.0 51.1
Total cash construction 90.0 324.5
AFUDC .8 2.4
Total construction including AFUDC (b) $ 90.8 $ 326.9
(a) Includes construction costs escalated at 1.4%, 2.2%, 3.0%
and 3.3% annually for the years 1997-2000, respectively.
(b) Does not include Ida-West equity investment in construction
as Ida-West develops its construction as a participant in
joint ventures which are not a part of the consolidated
entity.
These estimates are subject to constant revision in light of
changing economic, regulatory and environmental factors and
patterns of conservation.
The Company has no nuclear involvement and its future
construction plans do not include development of any nuclear
generation. The Company is looking at various options that may be
available to meet the future energy requirements of its customers
which include: (1) efficiency improvements on the Company's
generation, transmission and distribution systems, (2) purchased
power and exchange agreements with other utilities or other power
suppliers and (3) customer conservation. As additional energy
demands are placed upon the system, the project or projects best
meeting the changed requirements will be pursued.
FINANCING PROGRAM
The Company's five-year estimate of capital requirements and
sources of capital is $414.0 million outlined as follows:
1996 1997-2000
(Millions of Dollars)
Capital Requirements:
Net cash construction expenditures $ 90.0 $ 324.5
Conservation expenditures 2.6 5.2
Other cash expenditures 1.4 (9.7)
Total $ 94.0 $ 320.0
Sources of Capital:
Internal generation $ 82.6 $ 365.1
Short-term bank loans - Net 5.8 (41.3)
First mortgage bonds 30.0 110.0
Debt repayment (20.6) (112.8)
Common stock - -
Cash investments (increase) (3.8) (1.0)
Total (a) $ 94.0 $ 320.0
(a) Does not include Ida-West financing.
These estimates are subject to constant review in light of
changing economic, regulatory and environmental factors. Any
additional securities to be sold will depend upon market
conditions and other factors, but it is the Company's objective
to maintain capitalization ratios of approximately 45 percent
common equity, 8 to 10 percent preferred stock and the balance
long-term debt. The Company will continue to take advantage of
any refinancing opportunities as they become available.
Under the terms of the Indenture relating to the Company's First
Mortgage Bonds, net earnings must be at least two times the
annual interest on all bonds and other equal or senior debt. For
the twelve months ended December 31, 1995, net earnings were 6.68
times. Additional preferred stock may be issued when earnings for
twelve consecutive months within the preceding fifteen months are
at least equal to 1.5 times (until December 31, 2000, at which
time the issuance ratio will increase to 1.75 times) the
aggregate annual interest requirements on all debt securities and
dividend requirements on preferred stock. At December 31, 1995,
the actual preferred dividend earnings coverage was 2.82 times.
If the dividends on the shares of Auction Preferred Stock were to
reach the maximum allowed, the preferred dividend earnings
coverage would be 2.59 times. The Indenture and the Company's
Restated Articles of Incorporation are exhibits to the Form 10-K
and reference is made to them for a full and complete statement
of their provisions.
ITEM 2. PROPERTIES
The Company's system includes 17 hydroelectric generating plants
located in southern Idaho and eastern Oregon (detailed below) and
an interest in three coal-fired steam electric generating plants.
The system also includes approximately 4,642 miles of high
voltage transmission lines; 21 step-up transmission substations
located at power plants; 17 transmission substations; 7
transmission switching stations; and 194 energized distribution
substations (excludes mobile substations and dispatch centers).
The Company holds licenses under the Federal Power Act for 13
hydroelectric projects from the FERC. These and the other
generating stations and their capacities are listed below:
Maximum
Non-
Coincident Nameplate License
Operating Capacity kW
Capacity kW Expiration
Project
Properties Subject to Federal Licenses:
Lower Salmon 70,000 60,000 1997
Bliss 80,000 75,000 1998
Upper Salmon 39,000 34,500 1998
Shoshone Falls 12,500 12,500 1999
C J Strike 89,000 82,800 2000
Upper Malad 9,000 8,270 2004
Lower Malad 15,000 13,500 2004
Brownlee-Oxbow-Hells Canyon 1,398,000 1,166,900 2005
Swan Falls 25,547 25,000 2010
American Falls 112,420 92,340 2025
Cascade 14,000 12,420 2031
Twin Falls 54,300 52,737 2041
Milner 59,448 59,448 2038
Other Generating Plants:
Other Hydroelectric 10,400 11,300
Jim Bridger (Coal-Fired Station) 693,333 678,077
Valmy (Coal-Fired Station) 260,650 260,650
Boardman (Coal-Fired Station) 53,000 53,000
At December 31, 1995, the composite average ages of the principal
parts of the Company's system, based on dollar investment, were:
production plant, 16.3 years; transmission system and
substations, 17.6 years; and distribution lines and substations,
13.8 years. The Company considers its properties to be well
maintained and in good operating condition.
The Company owns in fee all of its principal plants and other
important units of real property, except for portions of certain
projects licensed under the Federal Power Act and reservoirs and
other easements, subject to the lien of its Mortgage and Deed of
Trust and the provisions of its project licenses, and to minor
defects common to properties of such size and character that do
not materially impair the value to, or the use by, the Company of
such properties.
As a result of various federal legislative actions and proposals
(such as the Electric Consumers Protection Act of 1986, Energy
Policy Act of 1992, Clean Water Act Reauthorization and
Endangered Species Act Reauthorization), a major issue facing the
Company is the relicensing of its hydro facilities. The
relicensing of these projects is not automatic under federal law.
The Company must demonstrate comprehensive usage of the
facilities, that it has been a conscientious steward of the
natural resource entrusted to it and that there is a strong
public interest in the Company continuing to hold the federal
licenses. Idaho Power is actively pursuing the relicensing of its
hydroelectric projects, a process that will continue for the next
10 to 15 years. The Company submitted its first applications for
license renewal to the FERC in December 1995. These first
applications seek renewal of the Company's licenses for its
Bliss, Upper Salmon Falls, and Lower Salmon Falls Hydroelectric
Projects. Although various federal requirements and issues must
be resolved through the relicensing process, the Company
anticipates that it's efforts will be successful. At this point,
however, the Company cannot predict what type of environmental or
operational requirements it may face, nor can it estimate the
eventual cost of relicensing.
Idaho Energy Resources Co. owns a one-third interest in certain
coal leases near the Jim Bridger generating plant in Wyoming from
which coal is mined and supplied to the plant.
Ida-West owns a 50 percent interest in five PURPA-qualified
facilities that have a total generating capacity of approximately
34 MW. The energy from these facilities is sold to the Company.
ITEM 3. LEGAL PROCEEDINGS
The Company is a defendant in a Superfund case entitled United
States of America vs. Pacific Hide & Fur Depot, et al., Civil No.
83-4062, pending in the United States District Court for the
District of Idaho. The suit involves PCB and PCB/lead
contamination at a scrap metal/recycling facility near Pocatello,
Idaho. The Company entered into a Partial Consent Decree which
was signed by the District Judge on September 26, 1989, wherein
the Company agreed to remediate PCBs at the site. Prior to
remediation, EPA notified the Company of the discovery of lead
and other metals contamination at levels of concern at the site.
Remediation activities were completed on October 21, 1992.
A Certification of Completion for the Operable Unit Remedial
Action dated March 31, 1993, was issued by EPA to the Company. On
August 30, 1993, Notice of the Lodging of an Amended Partial
Consent Decree was published in the Federal Register establishing
a period for public comment.
Pursuant to the Request for Public Comment, a number of
Potentially Responsible Parties (PRPs) involved with the lead
contamination at the site filed objections to the proposed
Amended Partial Consent Decree. The objections generally contend
that the government's information relating to the Company's
contribution to the lead contamination at the site is erroneous,
and that the Company's remedial efforts and related costs are
disproportionately low in relation to its liability.
The Amended Partial Consent Decree was lodged with the U. S.
District Court for the District of Idaho on December 12, 1994,
along with the EPA's Motion to Enter. The Amended Partial Consent
Decree provides that the Company is protected against any and all
claims for contribution by other PRPs, both as to the PCB and
lead contamination.
On January 24, 1995, the Company was advised that the PRP group
associated with lead contamination was objecting to the proposed
entry of the Amended Partial Consent Decree on the basis that the
Company has not paid its "fair share" of the remaining lead clean-
up costs which EPA currently estimates at approximately $5.0
million.
It was EPA's position that the Company, as an integral part of
its clean-up of the PCB contamination and PCB/lead contamination,
removed approximately 57 percent of the total lead contamination
from the entire site, even though the Company contributed only
10.5 percent of the total lead contamination.
On May 5, 1995, the Federal Magistrate entered a Report and
Recommendation to the District Judge wherein it was recommended
that the government's Motion for Entry of the Amended Partial
Consent Decree be granted. On May 18, 1995, the PRP group
associated with lead contamination filed objections to the
Magistrate's recommendations. The government filed its responses
to the objections on May 31, 1995.
On November 30, 1995, the District Judge issued a Memorandum
Decision and Order adopting the recommendations entered by the
Magistrate in the Report and Recommendation. The objecting PRPs
had the right but did not appeal the District Judge's Order to
the Ninth Circuit Court of Appeals. Based on the entry of the
Amended Consent Decree the Company will, with the EPA and the
Department of Justice, seek the Company's dismissal from the
case.
This matter has been previously reported in Form 10-K dated
March 9, 1989, March 8, 1990, March 14, 1991, March 16, 1992,
March 12, 1993, March 10, 1994, March 9, 1995 and other reports
filed with the Commission.
On February 16, 1994, an action for declaratory relief and breach
of contract entitled Idaho Power Company vs. Underwriters and
Lloyds London, et al., was filed by the Company in Federal
District Court in Pocatello, Idaho, against its solvent liability
insurers in the period of 1969 to 1974, arising out of the
insurer's denial of coverage for the Company's environmental
remediation of a hazardous waste site in Pocatello. The action
seeks a declaratory judgment that the policies cover the
Company's costs of defending claims related to the site and costs
of site remediation, and damages for the insurers' breach of the
insurance contracts based on the insurers' failure to pay such
costs.
Due to a case backlog in the Idaho District, the case was
assigned to a Federal Judge in the Eastern District of
Washington. In the action, the Company sought reimbursement for
approximately $6.1 million in indemnity and defense costs
associated with the remediation, together with prejudgment
interest and attorney fees and costs for the action.
The Company successfully settled its claim for coverage with the
Liquidation Trustee for the first layer insurer (which insurer is
now in liquidation) on several of the policies at issue,
resulting in a one-time payment of $827,500 to the Company in the
fall of 1994. In late 1995, the Company reached agreements with
two of the insurers to settle the claims against them on terms
favorable to the Company. In early 1996, the Company entered into
an oral agreement with the remaining insurers to settle its
claims with them on terms favorable to the Company, and expects
to reduce that agreement to writing and receive payment of the
sum called for by the agreement by mid-1996.
This matter has been previously reported in Form 10-K dated March
9, 1995 and other reports filed with the Commission.
On December 6, 1991, a complaint entitled Nez Perce Tribe,
Plaintiff, vs. Idaho Power Company, Defendant, Civil No. CIV 91-
0517-S-EJL, was filed against the Company in the United States
District Court for the District of Idaho.
On September 11, 1992, the Tribe filed an Amended Complaint in
which it amplified its original Complaint by asserting that
Brownlee, Oxbow and Hells Canyon Dams were "constructed, operated
and maintained in such a manner as to damage plaintiff's rights"
to harvest fish, which rights the Tribe asserts to be "present,
possessory property right(s)". As the basis for its alleged right
to recover damages from the Company, the Tribe asserts that the
Company negligently constructed, operated and maintained
Brownlee, Oxbow and Hells Canyon Dams, that the Company
negligently failed to prevent or mitigate harm to the Tribe, that
the Company intentionally and willfully destroyed, interfered
with, and dispossessed the Tribe of its property rights, and that
the Company improperly exercised dominion over the Tribe's
property, thus depriving the Tribe of its possession. The Tribe
seeks through its Amended Complaint to secure actual, incidental,
consequential and punitive damages in amounts to be proven at
trial.
On September 18, 1992, the Company filed a motion for summary
judgment in the hope of securing dismissal of the Tribe's action.
The District Court issued an Order of Reference sending the case
to a Federal Magistrate. On July 30, 1993, the Magistrate issued
a Report and Recommendation that the District Judge grant that
portion of the Company's motion for summary judgment regarding
the loss of fish.
On November 30, 1993, the District Court entered a Second Order
of Reference, in which the Court sent the case back to the
Magistrate for the Magistrate to make additional findings with
respect to the Tribe's contention that it is entitled to
compensation based on physical exclusion from its usual and
accustomed fishing places. On February 28, 1994, the Magistrate
issued a Second Report and Recommendation wherein it was
recommended that the District Court deny the Company's motion for
summary judgment as to the Tribe's claim for damages arising from
precluding the Tribe's access to its usual and accustomed fishing
places and reaffirmed its recommendation in the original Report
and Recommendation dated July 30, 1993, to grant the Company's
motion for summary judgment as to all other claims.
On September 28, 1994, the Federal District Judge issued an Order
rejecting the Second Report and Recommendation of the Magistrate
granting, in its entirety, the Company's motion for summary
judgment.
On November 8, 1994, the Tribe filed its Notice of Appeal with
the Ninth Circuit Court of Appeals. No date for oral argument on
the appeal has yet been set.
The Company and the Tribe have reached agreement on a proposed
settlement of this case. The Nez Perce Tribal Executive Committee
has approved the settlement, and the Company will submit the
proposed settlement to its Board of Directors at the March Board
meeting. If the Company's Board of Directors approves the
settlement, it will be submitted to appropriate state and federal
regulators for their approval.
This matter has been previously reported in Form 10-K dated
March 16, 1992, March 12, 1993, March 10, 1994, March 9, 1995 and
other reports filed with the Commission.
On October 6, 1994, the Company brought an action, Idaho Power
Company vs. Monsanto Company, et al., in the District Court of
the Fourth Judicial District of the State of Idaho, against
Monsanto Company, General Electric Company, Westinghouse Electric
Corporation, Schlumberger Industries, Inc., McGraw-Edison
Company, Asea Brown Boveri, Inc., and Cooper Industries, Inc. The
Complaint alleged fraudulent misrepresentation or omission of
material facts, and/or knowing failure to warn Idaho Power
Company of the hazards of PCBs, in connection with the sale,
service, replacement, maintenance and/or removal of electrical
equipment utilizing or contaminated with PCBs.
Pursuant to stipulations between the Company and the defendants,
the case was dismissed without prejudice by orders of the court
dated December 22, 1995, December 28, 1995, and January 6, 1996.
This matter has been previously reported in Form 10-K dated
March 9, 1995, and other reports filed with the Commission.
On November 30, 1995, a complaint entitled Idaho Power Company
vs. Cogeneration, Inc., Case No. 98467, was filed by the Company
in the District Court of the Fourth Judicial District of the
State of Idaho. The proceeding involves an effort by the Company
to terminate a firm energy sales agreement (FESA) for a small
hydroelectric generating plant.
As required by PURPA and the orders of the IPUC, on January 7,
1992, the Company entered into a 35-year FESA with Cogeneration,
Inc., to purchase the output of a 43-megawatt hydroelectric
generating project known as the Auger Falls Project. The FESA for
the Auger Falls Project was approved by the IPUC on January 27,
1992. The FESA required that on or before January 1, 1994,
Cogeneration, Inc., post cash or cash equivalent security in the
amount of approximately $1.9 million to assure performance of the
FESA. Cogeneration, Inc., failed to provide the security amount.
Consistent with the FESA, the Company filed a petition for
declaratory order with the IPUC requesting that the FESA be
terminated as a result of Cogeneration, Inc.'s breach.
Cogeneration, Inc., cross petitioned claiming that its failure
to perform was excused by the occurrence of an event of force
majeure. On April 17, 1995, the IPUC issued its order finding
that Cogeneration, Inc.'s failure to post the cash security on
January 1, 1994, was a default under the FESA and further finding
that the posting of the liquid security was required by the
public interest. Based upon those findings, the IPUC ordered
Cogeneration, Inc., to post the cash security prior to May 1,
1995. Cogeneration, Inc., failed to comply with the Commission's
order and has never posted the $1.9 million amount required by
the FESA.
After the IPUC order became final and non-appealable, the Company
filed this complaint for declaratory relief in the District Court
of the Fourth Judicial District. The Complaint sought a
determination by the district court that Cogeneration, Inc.'s
failure to provide the cash security and its violation of the
IPUC's orders requiring that it expeditiously provide the cash
security constituted material breaches of the FESA. The Company
asked the district court to find that as a matter of law Idaho
Power was entitled to either terminate or rescind the FESA.
In response to the Company's complaint, Cogeneration, Inc., filed
counterclaims alleging that the Company, by seeking to terminate
the FESA, had breached the FESA and was attempting to monopolize
the electric generation market and drive Cogeneration, Inc., out
of business. Cogeneration, Inc., alleged damages for breach in
excess of $50 million and requested that any damages be trebled
under the anti-trust laws.
On November 30, 1995, the district judge, by memorandum decision
found that Cogeneration, Inc., had materially breached the FESA
and the Company was entitled to either rescind or terminate the
FESA.
On February 16, 1996, Cogeneration, Inc. dismissed its anti-trust
claims against the Company and on February 23, 1996, the Idaho
Supreme Court granted Cogeneration, Inc.'s request for an
expedited appeal of the district courts decision establishing an
accelerated briefing schedule and scheduling oral argument for
May 10, 1996.
While the outcome of litigation is never certain, Idaho Power
believes that Cogeneration, Inc.'s counterclaims are without
merit.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None
EXECUTIVE OFFICERS OF THE REGISTRANT
The names, ages and positions of all of the executive officers of
the Company are listed below along with their business experience
during the past five years. Officers are elected annually by the
Board of Directors. There are no family relationships among these
officers, nor any arrangement or understanding between any
officer and any other person pursuant to which the officer was
elected.
Business Experience During
Name, Age and Position Past Five (5) Years
J. W. Marshall, 57 Appointed August 18, 1989.
Chairman of the Board
and Chief Executive
Officer
L. R. Gunnoe, 60 Appointed July 12, 1990.
President and Chief
Operating Officer
Daniel K. Bowers, 48 Appointed July 10, 1986.
Vice President and
Treasurer
J. LaMont Keen, 43 Appointed November 14, 1991.
Vice President and Mr. Keen was Controller prior to
Chief Financial Officer November 14, 1991.
Douglas H. Jackson, 59 Appointed July 12, 1990.
Vice President -
Distribution
C. N. Olson, 46 Appointed July 11, 1991. Mr. Olson
Vice President - was Senior Manager - Corporate
Corporate Services Services prior to July 11, 1991.
J. B. Packwood, 52 Appointed July 13, 1989.
Vice President -
Power Supply
Robert W. Stahman, 51 Appointed July 13, 1989.
Vice President, General
Counsel and Secretary
Harold J. Hochhalter, 60 Appointed January 9, 1992.
Controller and Chief Mr. Hochhalter was Manager of
Accounting Officer Corporate Accounting and Reporting
prior to January 9, 1992.
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON STOCK AND
RELATED STOCKHOLDER MATTERS
The Company has paid cash dividends on its common stock in each
year since 1918. For the years of 1993, 1994 and 1995, cash
dividends per share of common stock were $1.86. At the July 1995
meeting, the Board of Directors voted to maintain the annual
common dividend at $1.86 per share. It is the intention of the
Board of Directors to continue to pay dividends quarterly on the
common stock, but such dividends in the future will depend on
earnings, cash requirements of the Company and other factors.
The Company's common stock is listed on the New York and Pacific
Stock Exchanges. The following table indicates the reported high
and low sales price of the Company's common stock for the years
1994 and 1995, as reported by The Wall Street Journal as
composite tape transactions. The Company's year-end common stock
price was $30 per share and the number of stockholders of record
at December 31, 1995, was 30,795.
1994 Quarters
Common Stock, $2.50 par value: 1st 2nd 3rd 4th
High $ 30 5/8 $ 27 5/8 $ 24 7/8 $ 24 1/8
Low 26 7/8 21 3/4 22 1/2 22
Dividends paid per share
(cents) 46.5 46.5 46.5 46.5
1995 Quarters
Common Stock, $2.50 par value: 1st 2nd 3rd 4th
High $ 26 $ 26 3/4 $ 27 7/8 $ 30
Low 23 3/8 23 5/8 23 7/8 27 1/4
Dividends paid per share
(cents) 46.5 46.5 46.5 46.5
ITEM 6. SELECTED FINANCIAL DATA
SUMMARY OF OPERATIONS 1995 1994 1993 1992
(Thousands of Dollars)
Revenues:
General business $ 461,594 $ 457,354 $ 428,658 $ 431,818
Sales to other utilities 57,418 59,923 86,525 42,000
Other revenues 26,609 26,381 25,219 24,274
Total revenues 545,621 543,658 540,402 498,092
Expenses:
Purchased power 54,586 60,216 45,361 58,496
Fuel expense 54,691 94,888 87,855 96,710
Other operation and 169,959 154,742 164,388 137,547
maintenance
Depreciation 67,415 60,202 58,724 59,823
Taxes other than income taxes 22,979 23,945 22,129 20,562
Total expenses 369,630 393,993 378,457 373,138
Income from operations 175,991 149,665 161,945 124,954
Other income and deductions - (14,356) (12,160) (12,984) (11,133)
Net
Interest charges - Net 55,014 52,652 53,991 52,935
Income taxes 48,412 34,243 36,474 23,162
Cumulative effect of accruing
unbilled revenues - - - -
Net Income 86,921 74,930 84,464 59,990
Dividends on preferred stocks 7,991 7,398 6,009 5,516
Earnings on common stock 78,930 67,532 78,455 54,474
Dividends on common stock 69,941 69,594 67,959 65,043
Net change to retained earnings $ 8,989 $ (2,062) $ 10,496 $ (10,569)
CAPITALIZATION (000 omitted) % % % %
First mortgage bonds $ 470,000 } 45 $ 490,000 } 46 $ 490,000 } 47 $ 485,000 } 49
Other long-term debt 202,618 203,206 203,780 216,948
Mandatory redeemable preferred - } 9 - } 9 - } 9 - } 7
stock
Preferred stock 132,181 132,456 132,751 107,874
Common stock (incl. prem. & 452,948 } 46 452,962 } 45 439,467 } 44 412,998 } 44
exp.)
Retained earnings 229,827 220,838 222,900 212,404
Total capitalization $1,487,574 100 $1,499,462 100 $1,488,898 100 $1,435,224 100
Short-term borrowings $ 53,020 $ 55,000 $ 4,000 $ 6,000
outstanding
SUMMARY OF OPERATIONS 1991 1990 1989 1988
(Thousands of Dollars) (Cont'd)
Revenues:
General business $ 409,454 $ 401,350 $ 397,974 $ 362,050
Sales to other utilities 52,563 44,368 70,749 32,175
Other revenues 21,176 19,217 27,438 18,096
Total revenues 483,193 464,935 496,161 412,321
Expenses:
Purchased power 51,210 43,923 43,845 43,723
Fuel expense 75,161 77,606 77,127 74,528
Other operation and 151,593 134,126 132,114 116,230
maintenance
Depreciation 57,597 55,114 53,092 51,691
Taxes other than income taxes 21,168 20,752 20,213 19,301
Total expenses 356,729 331,521 326,391 305,473
Income from operations 126,464 133,414 169,770 106,848
Other income and deductions - (9,453) (11,666) (10,005) (6,552)
Net
Interest charges - Net 56,901 52,605 52,997 50,762
Income taxes 21,144 23,234 42,041 13,558
Cumulative effect of accruing
unbilled revenues - - - -
Net Income 57,872 69,241 84,737 49,080
Dividends on preferred stocks 4,904 4,279 4,285 4,293
Earnings on common stock 52,968 64,962 80,452 44,787
Dividends on common stock 63,197 63,197 62,177 61,159
Net change to retained earnings $ (10,229) $ 1,765 $ 18,275 $ (16,372)
CAPITALIZATION (000 omitted) % % % %
First mortgage bonds $ 435,000 } 48 $ 367,500 } 46 $ 377,000 } 47 $ 392,000 } 47
Other long-term debt 194,981 194,159 165,551 164,426
Mandatory redeemable preferred - } 8 - } 5 - } 5 - } 5
stock
Preferred stock 108,191 58,761 58,923 59,126
Common stock (incl. prem. & 356,824 } 44 358,078 } 49 357,986 } 48 357,866 } 48
exp.)
Retained earnings 222,973 233,241 231,476 213,201
Total capitalization $1,317,969 100 $1,211,739 100 $1,190,936 100 $1,186,619 100
Short-term borrowings $ 48,500 $ 48,280 $ 31,000 $ 37,000
outstanding
SUMMARY OF OPERATIONS 1987 1986 1985
(Thousands of Dollars) (Cont'd)
Revenues:
General business $ 343,899 $ 336,480 $ 336,705
Sales to other utilities 35,447 54,987 98,980
Other revenues 15,251 17,394 15,495
Total revenues 394,597 408,861 451,180
Expenses:
Purchased power 30,234 31,849 16,188
Fuel expense 65,934 31,260 81,961
Other operation and 114,235 114,407 125,728
maintenance
Depreciation 50,929 49,308 45,595
Taxes other than income taxes 19,072 18,539 16,790
Total expenses 280,404 245,363 286,262
Income from operations 114,193 163,498 164,918
Other income and deductions - (13,115) (17,064) (20,352)
Net
Interest charges - Net 51,843 51,206 47,891
Income taxes 27,246 50,923 52,556
Cumulative effect of accruing
unbilled revenues (11,302) - -
Net Income 59,521 78,433 84,823
Dividends on preferred stocks 4,298 10,553 12,447
Earnings on common stock 55,223 67,880 72,376
Dividends on common stock 61,159 59,755 56,277
Net change to retained earnings $ (5,936) $ 8,125 $ 16,099
CAPITALIZATION (000 omitted) % % %
First mortgage bonds $ 407,000 } 47 $ 432,000 } 47 $ 467,000 } 47
Other long-term debt 160,003 153,887 149,074
Mandatory redeemable preferred - } 5 - } 5 63,000 } 9
stock
Preferred stock 59,238 59,403 60,585
Common stock (incl. prem. & 357,797 } 48 357,708 } 48 355,007 } 44
exp.)
Retained earnings 229,573 235,509 230,558
Total capitalization $1,213,611 100 $ 1,238,507 100 $1,325,224 100
Short-term borrowings $ 4,000 $ 5,000 $ -
outstanding
FINANCIAL STATISTICS 1995 1994 1993 1992
Income from operations as a
percent
of total revenues 32.3% 27.5% 30.0% 25.1%
Times interest charges earned:
Before tax 3.26 3.01 3.14 2.50
After tax 2.40 2.38 2.50 2.08
Market-to-book ratio 165% 131% 170% 159%
Payout ratio 89% 103% 87% 120%
Return on year-end common
equity 11.56% 10.02% 1.84% 8.71%
Common stock data:
Earnings per average share
outstanding $ 2.10 $ 1.80 $ 2.14 $ 1.55
Dividends declared per share $ 1.86 $ 1.86 $ 1.86 $ 1.86
Book value per share $ 18.15 $ 17.91 $ 17.86 $ 17.28
Average shares outstanding 37,612 37,499 36,675 35,116
(000 omitted)
Common shareowners 30,795 26,209 26,870 27,834
* Includes cumulative effect
of accounting change
CUSTOMER DATA
General business data:
Energy sales - kWh
(000,000 omitted) 11,983 12,194 11,406 11,606
Number of customers 340,708 330,308 317,772 307,567
Residential customer data:
Number of customers 282,797 274,187 263,682 255,022
Average kWh use per customer 13,475 14,159 14,587 13,856
Average rate per kWh (cents) 5.16 4.83 4.82 4.80
OTHER STATISTICS
Total assets (000 omitted) $2,241,753 $2,191,816 $2,097,417 $1,862,307
Gross plant additions (000
omitted) $ 87,297 $ 107,667 $ 116,972 $ 118,920
Number of employees (full-time) 1,522 1,609 1,654 1,638
FINANCIAL STATISTICS (Cont'd) 1991 1990 1989 1988
Income from operations as a
percent of total revenues 26.2% 28.7% 34.2% 25.9%
Times interest charges earned:
Before tax 2.34 2.72 3.30 2.18
After tax 1 2.29 2.53 1.93
Market-to-book ratio 168% 148% 169% 138%
Payout ratio 119% 97% 77% 137%
Return on year-end common 9.14% 10.99% 13.65% 7.84%
equity
Common stock data:
Earnings per average share $ 1.56 $ 1.91 $ 2.37 $ 1.32
outstanding
Dividends declared per share $ 1.86 $ 1.86 $ 1.83 $ 1.80
Book value per share $ 17.07 $ 17.40 $ 17.35 $ 16.81
Average shares outstanding
000 omitted) 33,977 33,977 33,977 33,977
Common shareowners 28,069 29,080 30,291 32,225
* Includes cumulative effect
accounting change
CUSTOMER DATA
General business data:
Energy sales - kWh
(000,000 omitted) 11,266 11,086 11,069 10,563
Number of customers 297,808 291,800 284,363 279,529
Residential customer data:
Number of customers 246,689 241,790 236,008 232,650
Average kWh use per customer 14,845 14,281 14,923 14,364
Average rate per kWh (cents) 4.72 4.73 4.69 4.47
OTHER STATISTICS
Total assets (000 omitted) $1,773,674 $1,680,110 $1,625,120 $1,608,935
Gross plant additions (000 $ 135,904 $ 80,117 $ 62,094 $ 64,358
omitted)
Number of employees (full-time) 1,626 1,574 1,528 1,500
FINANCIAL STATISTICS (Cont'd) 1987 1986 1985
Income from operations as a
percent of total revenues 28.9% 40.0% 36.6%
Times interest charges earned:
Before tax 2.76* 3.40 3.61
After tax 2.10* 2.46 2.61
Market-to-book ratio 127% 150% 133%
Payout ratio 111% 88% 78%
Return on year-end common 9.40% 11.44% 12.36%
equity
Common stock data:
Earnings per average share $ 1.63* $ 2.00 $ 2.16
outstanding
Dividends declared per share $ 1.80 $ 1.76 $ 1.68
Book value per share $ 17.29 $ 17.46 $ 17.29
Average shares outstanding 33,977 33,961 33,544
(000 omitted)
Common shareowners 33,733 34,456 35,959
* Includes cumulative effect
of accounting change
CUSTOMER DATA
General business data:
Energy sales - kWh
(000,000 omitted) 10,175 9,938 10,366
Number of customers 276,249 274,129 272,155
Residential customer data:
Number of customers 230,486 228,921 227,562
Average kWh use per customer 13,785 14,541 15,432
Average rate per kWh (cents 4.34 4.21 3.98
OTHER STATISTICS
Total assets (000 omitted) $1,602,311 $1,621,887 $1,646,847
Gross plant additions (000 $ 38,929 $ 50,257 $ 74,064
omitted)
Number of employees (full-time) 1,521 1,524 1,568
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
OVERVIEW
Idaho Power Company's consolidated financial statements represent
the Company and its five wholly-owned subsidiaries: Idaho Energy
Resources Company (IERCo); Ida-West Energy Company (Ida-West);
IDACORP, Inc.; Idaho Utility Products Company (IUPCo); and
Stellar Dynamics. This discussion uses the terms Idaho Power and
the Company interchangeably to refer to Idaho Power Company and
its subsidiaries.
EARNINGS PER SHARE AND BOOK VALUE
Three primary factors affected earnings per share in 1995: the
resolution of rate cases in Idaho and Oregon, improved
precipitation and streamflow conditions, and successful cost-
cutting measures. In January 1995, the Company completed its
general revenue requirements case in Idaho with a $17.2 million
(4.2 percent) increase in rates. The Company later reached
settlements with the Idaho Public Utilities Commission (IPUC) on
the Twin Falls case ($3.8 million) and with the Oregon Public
Utility Commission (OPUC) on general rate relief ($1.3 million).
These rate increases were partially offset by weather conditions
that reduced residential and irrigation energy demands. An
unusually warm winter and a cool summer created a surplus energy
market in which prices on sales for resale dropped to record
lows. However, abundant precipitation within the Company's
service territory allowed Idaho Power to capitalize on its low-
cost hydroelectric generating system, dramatically reducing fuel
expenses and purchased power costs. Finally, the Company
instituted aggressive cost containment and efficiency measures to
manage capital and operating expenses. Total operating expenses
were down $24.4 million, while construction expenditures were
reduced $26.6 million from 1994 amounts.
Earnings per share of common stock in 1995 totaled $2.10, up from
the $1.80 earned in 1994 and only slightly lower than the $2.14
earned in 1993. The 1995 earnings equate to an 11.6 percent
earned return on year-end common equity, as compared to the 10.0
percent earned in 1994 and the 11.8 percent earned in 1993. At
December 31, 1995, the book value per share of common stock was
$18.15.
Results of Operations
Energy Demand and Customer Growth
Milder winter and spring temperatures reduced 1995 residential
loads for heating and cooling, while the wet, cool spring reduced
irrigation loads. In contrast, 1994 was characterized by a
prolonged period of high summer temperatures that led to sharp
increases in energy demand and led to a record peak system load.
While energy demand was down, the Company continued its growth of
new customers by adding 10,400 new general business customers
during 1995. This increase marks 1995 as the Company's fourth
best year in terms of customer growth, coming on the heels of
1994's record-setting growth of 12,536 new general business
customers. During 1995, Idaho Power added 8,610 residential
customers, 1,636 commercial and industrial customers, and 154
irrigation customers.
Economy
Idaho's economy continues to grow at a healthy pace. For the
twelve months ending September 1995, non-agricultural employment
in Idaho rose 4.4 percent, making Idaho the eighth fastest
growing state in the nation. Idaho's per capita income grew by
5.8 percent in 1994 and by an average 6.3 percent through the
first half of 1995.
While job and income growth have kept Idaho near the top of the
national rankings during 1995, monthly employment gains from 1994
levels reveal a slackening in the rate of job growth. In
addition, some of Idaho's larger employers announced plans for
restructuring and consolidation. Idaho's September 1995 non-
agricultural employment was up 1.9 percent, while manufacturing,
trade, and services employment posted gains of 1.5 percent, 3.2
percent, and 2.6 percent respectively when compared to September
1994. Non-agricultural employment growth in the Boise
Metropolitan Statistical Area remains relatively high, with a net
increase of 4.2 percent (7,300 jobs) between September 1994 and
September 1995.
Further restructuring within the forest products industry, a
slowing of residential construction activity (due to a lower
level of economic activity), and changes slated for the Idaho
National Engineering Laboratory (INEL) near Idaho Falls should
keep Idaho's employment growth in 1996 and 1997 within the 2.5
percent to 3.0 percent range, as compared to the average of 6.9
percent experienced during 1993 and 1994.
The number of residential customers in Idaho Power's service area
grew by 3.4 percent in 1993, 4.0 percent in 1994, and 3.1 percent
in 1995. Over the next five years, the Company projects that the
number of new households in its service area will grow by an
average annual rate of 2.4 percent.
Revenues
For the three-year period 1993-1995, the Company received an
average 86 percent of its operating revenues from electric sales
in Idaho, 5 percent in Oregon, less than 1 percent in Nevada, and
9 percent from the wholesale market. For the same three-year
period, the average percentages of total operating revenues by
customer category were as follows:
- 34 percent from residential customers;
- 30 percent from a combination of irrigation customers,
street lighting customers, and commercial customers with less
than 1,000 kW demand;
- 19 percent from industrial customers with demand of 1,000 kW
or greater;
- 13 percent from sales to other utilities and interchange
arrangements; and
- 4 percent from miscellaneous revenue.
The Company's energy sales to general business customers fell 1.7
percent in 1993, increased 6.9 percent in 1994, but decreased 1.7
percent in 1995. The sales increase in 1994 reflects the strong
economic growth in Idaho Power's service territory; increases in
new customers served; and hot, dry summer weather. In 1995,
residential usage was down 1.5 percent, due to the mild weather,
even with an increase of new customers during the year. The
declines in 1993 and 1995 may be traced to wet spring weather
that reduced irrigation kilowatt-hour sales in those years by
28.8 percent and 25.2 percent respectively. In addition,
temporary operational changes made in 1993 by two of the
Company's large industrial customers lowered their energy
consumption. FMC Corporation periodically curtailed 1993
operations at its elemental phosphorous production plant in
response to market conditions for its product. The INEL also
reduced its 1993 electrical usage. However, both FMC and INEL
returned to a higher level of operation during 1994. Those two
entities, along with Boise's Micron Technology, increased their
energy usage in 1995.
General business revenues represent approximately 83 percent of
the Company's total operating revenues. For 1993, general
business revenues were $428.7 million, for 1994 $457.4 million,
and for 1995 $461.6 million. The 1994 increase reflects above-
normal summer temperatures that increased irrigation revenues by
$16.2 million (33.2 percent). The 1995 increase reflects rate
increases during the year and increased sales to some industrial
customers. The number of general business customers served
increased by 33,141 (10.8 percent) during the three-year period.
The average residential customer used 14,587 kilowatt-hours (kWh)
of electricity in 1993, 14,159 kWh in 1994, and 13,475 kWh in
1995, primarily due to varied weather patterns.
Total operating revenues increased by $42.3 million (8.5 percent)
in 1993, $3.3 million (0.6 percent) in 1994, and $2.0 million
(0.4 percent) in 1995. Increased opportunity sales to other
utilities created the 1993 increase in total operating revenue.
Customer growth, coupled with above-normal summer temperatures,
accounted for the 1994 increase. However, that increase was
offset by a decline in opportunity sales caused by reduced
streamflows. The increase for 1995 reflects the continuing
strength of economic growth in the Company's service territory,
the continued increase in new customers, and rate increases in
the Idaho jurisdiction. The 1995 increase was partially offset by
reduced revenues from sales for resale.
Off-System Sales
Revenues from sales to other utilities rose $44.5 million in
1993, declined $26.6 million in 1994, and declined by an
additional $2.5 million in 1995. Off-system sales are composed of
firm sales (long-term contracts) and opportunity sales made on a
when-available basis. The volume and price of these sales depend
on the Company's firm energy demand, hydroelectric generating
conditions in its service territory, and market conditions
throughout the West. Revenues from firm sales to other utilities
totaled $45.4 million in 1993, $53.6 million in 1994, and $45.2
million in 1995. Revenues from opportunity sales to other
utilities totaled $41.1 million in 1993, $6.3 million in 1994,
and $12.2 million in 1995. The return to more normal
hydroelectric generating conditions in 1993 increased the volume
of sales and revenue dramatically, while drought conditions
reduced opportunity sales in 1994. In 1995, improved
hydroelectric generating conditions created an increase in
opportunity energy sales. However, reduced demand on the energy
market cut the prices of such sales by 53 percent when compared
to those received in 1994.
Expenses
Total operating expenses rose by $5.3 million in 1993 and $15.5
million in 1994, but decreased by $24.4 million in 1995. The 1993
rise in operating expenses reflects the deferral of certain 1992
drought-related net power supply costs to 1993, as authorized by
the IPUC. Maintenance expenses also increased in 1993 with that
year's return to improved hydroelectric operating conditions. The
added expense for 1994 reflects drought conditions, which
increased the Company's reliance on thermal generation and
purchased power. The decrease in 1995 may be traced to improved
hydroelectric operating conditions, which lowered purchased power
and fuel expenses by $5.6 million and $40.2 million respectively.
Purchased power expenses fluctuated during the three-year period.
This situation reflects necessity purchases from neighboring
utilities during the 1994 drought, and increased purchases in
1993 from cogeneration and small power production (CSPP) projects
as hydroelectric generating conditions improved. Purchased power
expenses were lower in 1995 with the return to more normal hydro
conditions. The decrease was tempered by economy purchases made
while the market prices for off-system sales were soft and
increased purchases from CSPP projects.
All other operation and maintenance expenses fluctuated during
the three-year period, with a cumulative increase of $32.4
million. These variations are due, in part, to increases in
payroll and benefits, changes in operation and maintenance due to
water conditions, but were partially reduced by the successful
efforts of the Company's employees to manage operating costs.
Depreciation expense was up for the three-year period by $7.6
million (12.7 percent), due to a greater plant investment base.
Taxes other than income taxes rose $2.4 million (11.8 percent) as
a result of additional property taxes and taxes on the increased
generation and sale of hydroelectric power.
Interest Charges
Interest charges on long-term debt fluctuated during the three-
year period, with a cumulative decrease of $1.0 million. This
decrease reflects the maturity, early redemption, and issuance of
several series of first mortgage bonds at reduced or lower
interest rates. The Company took advantage of declining interest
rates during 1993 to refinance several higher-cost bond issues.
These refinancings reduced the overall cost of debt and annual
interest expense by an amount that largely offset the cost of
additional financing (see Note 5 of Notes to Consolidated
Financial Statements).
Interest on short-term debt rose during the three-year period due
to fluctuating interest rates during the three-year period, as
well as to a higher level of short-term borrowings. At December
31, 1995, the Company's short-term borrowings totaled $53.0
million (see Note 7 of Notes to Consolidated Financial
Statements).
Income Taxes
In August 1993, the U.S. Congress enacted the Omnibus Budget
Reconciliation Act. Among other things, the Act raised the
statutory corporate federal income tax rate from 34 percent to 35
percent, retroactive to January 1, 1993. Accordingly, taxes on
current income were computed at the higher rate. Also in 1993,
the Company settled with the Internal Revenue Service (IRS)
federal income tax liabilities for the 1987-1990 tax years. In
1994, the Company settled federal income tax liabilities for the
1991-1992 tax years, except for immaterial amounts relating to a
partnership.
Precipitation and Streamflows
Idaho Power analyzes precipitation and streamflow conditions
based on the effect on Brownlee Reservoir, primary water source
for the three Hells Canyon hydroelectric projects. In normal
years, these three projects combine to produce about half of the
Company's generated electricity. In 1994, below-normal
precipitation created drought conditions and reduced the amount
of water flowing into the Company's reservoir system. However, in
1993 and 1995, Idaho Power's service territory experienced above
average water years. Between April and July 1995, the Company
recorded 6.6 million acre feet (MAF) of water flowing into
Brownlee Reservoir. This figure is 110 percent of 1993's 6.0 MAF,
236 percent of 1994's 2.8 MAF, and 138 percent of the 66-year
median of 4.8 MAF.
The early indications for 1996 are promising. As of February 1,
1996, reservoir storage above Brownlee Reservoir was at 81
percent of capacity compared to a normal of 62 percent The
average snow water equivalent for the Snake River above Brownlee
Reservoir was 116 percent of the 30-year average, compared to 114
percent of the average at this time last year.
Energy Requirements
With precipitation and streamflow conditions above normal in
1995, hydroelectric generation accounted for 58 percent of the
Company's total energy requirements. This figure is an
improvement over 1993's 52 percent, and is substantially higher
than 1994's 40 percent. During 1995, thermal generation accounted
for 29 percent of total energy requirements, while purchased
power and other interchange supplied 13 percent. Under
historically normal conditions, the Company's hydro system
supplies approximately 57 percent of its total energy
requirements, with thermal generation accounting for 34 percent
and purchased power and other interchanges contributing the
remaining 9 percent.
The Company expects to meet 1996's projected energy loads by
using its hydro and coal-fired facilities and its strategic
geographic location, which presents excellent opportunities to
purchase, sell, exchange, and transmit Northwest energy.
Regulatory Issues
Power Cost Adjustment
Since 1993, the Idaho Power's Power Cost Adjustment (PCA)
mechanism has allowed the Company to collect or to refund the
differences between actual net power supply costs and those
allowed in the Company's Idaho base rates. Deviations from
forecasted costs are deferred with interest and trued up in the
following year. With the IPUC's revenue requirement order on
February 1, 1995, the PCA mechanism increased to a 90 percent
recovery level from its original 60 percent. The Company filed
its 1995 PCA application with the IPUC on April 15, 1995,
requesting a decrease in PCA rates for the Idaho jurisdiction.
The decrease (in effect from May 16, 1995 through May 15, 1996)
was approximately $8.2 million (1.9 percent), including last
year's true-up, still in excess of base rates. At December 31,
1995, the Company had recorded $1.0 million less in power supply
costs then projected in the 1995 forecast. The Company has
deferred this cumulative amount and will include it as a
reduction in the 1996 PCA true-up.
General Revenue Requirement Case
On June 30, 1994, Idaho Power filed an application with the IPUC
to increase rates in its Idaho jurisdiction. The Company based
its application on calendar year 1993, using a thirteen-month
average rate base annualized for its new Swan Falls production
project and a year-end capitalization structure. In its
application, the Company requested $37.1 million in general rate
relief, representing a 9.09 percent increase in rates, a 12.50
percent return on equity, and a 9.88 percent overall rate of
return. On January 31, 1995, the Company received IPUC Order No.
25880, which authorized $17.2 million in general rate relief,
representing a 4.2 percent overall increase in Idaho retail
rates. The relief was based on an 11.0 percent allowed return on
equity and an overall rate of return of 9.2 percent. The increase
in Idaho retail rates went into effect on February 1, 1995.
Twin Falls Rate Case
In August 1995, the IPUC issued an order authorizing the Company
to increase its Idaho retail rates on an annual basis by $3.8
million (0.9 percent). This increase was uniform to all customer
classes, as well as to special contract customers. The Company
originally applied for a $6.3 million (1.5 percent) increase to
recover capital costs and related expenses associated with the
construction of a new 43.5 megawatt (MW) power plant at its Twin
Falls hydro facility, along with additional plant investments at
the Swan Falls hydro facility since the filing of its last
general rate case.
The major issue in this case was whether the reduced power supply
costs resulting from the inclusion of the Twin Falls hydro
expansion would be recognized explicitly through a reduction in
base energy rates or implicitly through the PCA. The Company
reached a compromise with the IPUC staff on the overall revenue
requirement and agreed to recognize benefits up front in base
rates, instead of flowing the benefits through the PCA. As a
result, the Company's original $6.3 million request was reduced
by $1.9 million. The effect on projected Company earnings is only
10 percent of this amount ($190,000), since all but 10 percent of
the power supply cost reduction would have been passed through to
Idaho customers in the next PCA adjustment. The IPUC action
enabled the Company to recover the capital costs of a plant
addition within weeks of the plant becoming operational.
Regulatory Settlement
On August 3, 1995, the Company filed a proposal with the IPUC to
defer and amortize costs associated with its internal
transformation process and acceleration of amortization of
regulatory liabilities associated with accumulated deferred
investment tax credits (ADITCs). The IPUC approved a settlement
agreement confirming the proposal, which allows the Company to
accelerate the amortization of the regulatory liabilities
associated with ADITCs whenever the Company's year-end return on
equity falls below 11.5 percent. In addition, the order allows
the Company to defer certain costs associated with its corporate
reorganization as regulatory assets and amortize them over a 10-
year period.
The terms and conditions of the Order will remain in effect
through 1999. Under the Order, when the Company's actual earnings
in a given year exceed an 11.75 percent return on year-end common
equity, the Company will refund 50 percent of the excess through
its next PCA adjustment.
Other important points in the Order are: (1) the Company may
accelerate a maximum of $30 million of regulatory liabilities
associated with ADITCs over the five-year period; (2) the Company
will not be allowed to increase its Idaho general rates prior to
January 1, 2000, except under special conditions as defined in
the Settlement Agreement; and (3) Idaho Power agrees that its
quality of service will not decline as a result of corporate
reorganization. The proposed accounting treatment of deferred
investment tax credits has been submitted to the IRS for
approval. On November 22, 1995, the Idaho State Tax Commission
approved the accounting treatment for the Idaho ADITCs. No
accelerated ADITC was recognized in 1995.
Cogeneration and Small Power Production Contracts
In September 1993, the Company submitted a detailed position
paper to its state regulators and other interested parties. This
report outlined proposed changes in the Company's resource
acquisition policy. In light of the potential deregulation of the
electric utility industry and a more competitive power supply
marketplace, Idaho Power's position was that current resource
acquisition policies had to be changed to avoid burdening the
Company and its customers with unnecessary future power supply
costs. In December 1993, the Company filed with the IPUC for
permission to approve lower published prices for new CSPP
contracts. In response to the Company's filing, the IPUC issued
an order on January 31, 1995, approving lower published CSPP
rates. In addition, the IPUC determined that negotiated rates for
future CSPP projects larger than 1 MW should be tied more closely
to values determined in the Company's integrated resource
planning (IRP) process.
Oregon General Rate Relief
In May 1995, Idaho Power filed an application with the OPUC
seeking general rate relief of approximately $3.4 million, or a
16.65 percent increase. The Company later negotiated a Settlement
Stipulation with the OPUC staff, the Company's Oregon industrial
customers, and the Citizens Utility Board of Oregon. The
settlement grants Idaho Power a $1.3 million general rate
increase for its Oregon retail customers. The OPUC approved the
settlement agreement on November 28, 1995.
Drought-Related Rate Relief
In response to the Company's April 1995 application, the OPUC
granted $1.5 million in drought-related rate relief. The OPUC
Order allows recovery of the $1.5 million through the continued
application of an existing increase authorized in July 1993 (for
1992 drought relief). The rate increase will remain in effect for
approximately 34 months beginning in July 1995. The Company had
deferred, with interest, increased power supply costs between May
1994 and December 31, 1994.
Subsidiaries
Ida-West Energy Company
This wholly-owned subsidiary of the Company owns, through various
partnerships, 50 percent of five Idaho hydroelectric projects
with a total generating capacity of approximately 34 megawatts
(MW). Third parties unaffiliated with Ida-West own the remaining
50 percent of these projects, thus satisfying the "qualifying
facility" status under PURPA guidelines. The partnerships have
obtained project financing (non-recourse to the Company) for each
of these facilities.
As a part of its Resource Contingency Program, the Bonneville
Power Administration (BPA) requested proposals to provide up to
800 average MW of energy options. Ida-West, along with two
partners, submitted a proposal for a 227 MW gas-fired
cogeneration project to be located near Hermiston, Oregon. On
June 4, 1993, BPA selected three projects_including that of the
partnership_for participation in the program. The partnership and
BPA signed an option development agreement granting BPA an option
to acquire energy and capacity from the project any time during a
five-year option hold period after all option development period
tasks, including permitting, have been completed. The option also
entitles the partnership to BPA reimbursement for certain
development costs, based on the achievement of certain
milestones. This option includes an exclusive right to acquire
energy and capacity from a second 233 MW unit at the site during
the same five-year option hold period. In March 1994, BPA and the
partnership reached an additional agreement on the power purchase
contract, setting forth the terms and conditions by which BPA
will purchase energy and capacity from the project upon exercise
of the option. The partnership expects to complete development
period tasks during the first quarter of 1996. Project financing
for construction costs would be non-recourse to the Company.
The Company has invested $20 million in Ida-West. Ida-West
continues an active search for new projects.
IDACORP, Inc.
Through this wholly-owned subsidiary, the Company is
participating in three affordable housing programs. These
investments provide a return to IDACORP by reducing the Company's
federal income taxes and by assuring a return on investment
through tax credits and tax depreciation benefits.
Liquidity and Capital Resources
Cash Flow
The Company's net cash generation from operations totaled $437.9
million for the three-year period 1993-1995. After deducting
common and preferred dividends of $227.7 million, net cash
generation from operations provided approximately $210.2 million
for the Company's construction program and other capital
requirements.
Internal cash generation after dividends provided 54 percent of
the Company's total capital requirements in 1993, 41 percent in
1994, and 101 percent in 1995. The Company projects that internal
cash generation after dividends will provide approximately 90
percent of total capital requirements in 1996 and over 100
percent during the five-year period 1996-2000. Idaho Power
expects to continue financing its construction program and other
capital requirements with both internally generated funds and, to
the extent necessary, externally financed capital. During the
forecast period, the Company also has first mortgage bond
maturities of $20.0 million in 1996, $30.0 million in 1998, and
$80.0 million in 2000. At January 1, 1996, the Company's lines of
credit maintained with various banks totaled $85.0 million (see
Note 7 of Notes to Consolidated Financial Statements).
Construction Program
The Company's consolidated cash construction expenditures totaled
$122.9 million in 1993, $110.5 million in 1994, and $84.0 million
in 1995. Approximately 36 percent of these expenditures were for
generation facilities, 15 percent for transmission facilities, 38
percent for distribution facilities, and 11 percent for general
plant and equipment.
Swan Falls Project
Early in the spring of 1994, the Company completed testing of the
renovated Swan Falls Hydroelectric Project and declared both
units available for commercial operation. Additional work to
preserve the old powerhouse as an historical site began during
the year, with work to establish a museum on the site scheduled
for completion in 1996.
Twin Falls Project
In July 1995, the Company completed testing of the new expansion
turbine at its Twin Falls Hydroelectric Project and declared the
unit available for commercial operation. This project added 43.5
MW of capacity to the Company's generation system and a second
powerhouse to the Twin Falls site.
Southwest Intertie Project
Idaho Power is continuing to study the economic feasibility of
constructing the Southwest Intertie Project (SWIP) to capitalize
on its strategic location between the Intermountain West and the
Pacific Northwest. The Company's SWIP proposal calls for a 500-
mile, 500 kilovolt (kV) transmission line that would serve as a
major north-south transmission artery, interconnecting the
Company's system with those of utilities in California and the
Southwest. In December 1994, the U.S. Bureau of Land Management
(BLM) issued a favorable record of decision on the Company's
environmental impact statement and granted the project a right-of-
way across public lands in Idaho, Nevada, and Utah. Idaho Power
intends to retain up to 20 percent of ownership and capacity in
the 1,200 MW project. The SWIP may be built in segments as
warranted by demand for its transmission services. Idaho Power
and the BLM are working on a detailed, site-specific
construction, operation, and maintenance plan aimed at mitigating
the environmental impact of the project.
The Company sent participation packages to interested parties and
received capacity requests from these groups during the fourth
quarter of 1995. Ownership allocation has been completed between
the six interested parties and negotiations are in process for
the execution of the Memorandum of Agreement (MOA). At the time
of execution of the MOA the Company is requiring each party to
pay its share of the approximately $8.5 million expended for
environmental permitting, right-of-way acquisition, and related
development activities. The SWIP owners will then form an
Executive Committee with voting rights proportional to their
share of the project. The Executive Committee will oversee
development activities for the SWIP and related projects.
The Company is positioning SWIP as an open-access transmission
opportunity for participants, in line with the Notice of Proposed
Rulemaking (NOPR) issued by the Federal Energy Regulatory
Commission (FERC).
Financing Program
Capital Structure
The Company's capital structure (as illustrated in Selected
Financial Data) fluctuated during the three-year period, with
common equity growing to 46 percent, preferred staying at 9
percent, and long-term debt falling to 45 percent. The Company's
objective is to maintain capitalization ratios of approximately
45 percent common equity, 8-10 percent preferred stock, and the
balance in long-term debt. The Company's pre-tax interest
coverage ratios were 3.14 times in 1993, 3.01 times in 1994, and
3.26 times in 1995. The Company has on file a shelf registration
statement for the issuance of first mortgage bonds and/or
preferred stock, with an aggregate principal amount not to exceed
$200 million.
Common Stock
During the period of January 1992 through May 1994, the Company
issued original issue shares of common stock for its Dividend
Reinvestment and Stock Purchase Plan, and for its Employee
Savings Plan. During 1993 and 1994, common shares totaling
898,528 and 527,296, respectively, were issued to these plans.
During 1995 no original issue shares were issued pursuant to
these plans. The Company used the net proceeds from these issues
for its ongoing construction program.
Environmental Issues
Salmon Recovery Plan
Work continues on the development of a comprehensive and
scientifically credible plan to ensure the long-term survival of
anadromous fish runs on the Columbia and Lower Snake Rivers.
In mid-August 1994, the federal government changed its
designation of the Fall Chinook Salmon from Threatened to
Endangered. The Company does not anticipate that the new
designation will have any major effects on its operations. In
September 1991, the Company modified operations at its three-dam
Hells Canyon Hydroelectric Complex to protect the Fall Chinook
downstream during spawning and juvenile emergence. From its
start, the Company's Fall Chinook program has exceeded the
protection requirements for threatened species, affording the
fish the same high level of protection due an endangered species.
In March of 1995, the National Marine Fisheries Service (NMFS)
released a Proposed Recovery Plan for the listed Snake River
Salmon. The NMFS accepted public comment on the Plan through
December of 1995. As drafted, the Plan would not require any
change to the Company's current operations for salmon. Pending
completion of a final recovery plan by the NMFS, the U.S. Army
Corps of Engineers and other governmental agencies operating
federally-owned dams and reservoirs on the Snake and Columbia
Rivers will continue to consult with the NMFS regarding ongoing
system operations. These interim operations are not expected to
change the Company's current operations for salmon.
The Northwest Power Planning Council (NWPPC) issued its recovery
plan for Snake River anadromous fish, the Strategy for Salmon, on
December 15, 1994. The NWPPC plan calls on the U. S. Bureau of
Reclamation (BOR) to acquire 500,000 acre-feet of water within
the Snake River Basin by 1996, and an additional 500,000 acre-
feet by 1998. The water is to be acquired from willing sellers.
Thus far, the BOR has indicated it does not intend to comply with
the request to acquire 1,000,000 acre-feet of additional water.
However, if the BOR does comply and successfully implements the
request, its movement of additional water could have a material
impact on the Company's Power supply costs. The strategy for
Salmon also calls for the Company to contribute 427,000 acre-feet
of water from Brownlee Reservoir as required in the NMFS Proposed
Recovery Plan. The Company is presently negotiating with BPA to
obtain reimbursement for the costs associated with lost
generation and the storing of energy resulting from the release
of the 427,000 acre-feet.
Nez Perce Lawsuit
On December 6, 1991, the Nez Perce Tribe filed a civil action
against the Company in the U.S. District Court for the District
of Idaho. The Tribe alleged that the Company's construction,
operation, and maintenance of the three-dam Hells Canyon
Hydroelectric Project prevented anadromous fish from reaching
their traditional spawning areas, destroyed certain fish runs,
and denied access to certain of the Tribe's usual and accustomed
fishing places. These actions allegedly deprived the Nez Perce
Tribe of its treaty rights to take fish from the Columbia and
Snake Rivers. The Tribe is seeking compensatory and punitive
damages, each in an amount to be proven at trial.
Idaho Power maintains that the suit is without merit and asked
the federal court to issue a summary judgment dismissing the
action. The Company believes that the responsibility for concerns
expressed by the Nez Perce Tribe lies with the United States
government. The Hells Canyon Project was licensed by the federal
government, was built in accordance with federally approved
plans, and is operated subject to federal regulation. The Company
has complied with the government's requirements to mitigate any
effects that the Project may have had on the fisheries.
On January 19, 1993, the Court took the Company's motion for
summary judgment under advisement. On July 30, 1993, U.S.
Magistrate Judge Larry Boyle issued a Report and Recommendation
to the District Judge. Judge Boyle recommended that the District
Judge grant that portion of the Company's motion for summary
judgment regarding the loss of fish and deny the portion of its
motion dealing with the Tribe's claim to compensation for
exclusion from its usual and accustomed fishing sites. On March
21, 1994, U.S. District Judge Harold L. Ryan upheld Judge Boyle's
recommendation regarding fish losses and took the question of
compensation for exclusion from fishing sites under advisement.
On September 28, 1994, after reviewing responses and objections
on that issue, Judge Ryan rejected the Tribe's claim and granted
the final portion of the company's motion for summary judgment.
The Tribe has appealed Judge Ryan's decision to the Ninth Circuit
Court of Appeals and the case has been fully briefed and
submitted to the Court. No date has been set for oral argument on
the appeal.
The Company and the Tribe have reached agreement on a proposed
settlement of this case. The Nez Perce Tribal Executive Committee
has proposed a settlement and the Company will submit the
proposed settlement to its Board of Directors at the March board
meeting. If the Company's Board of Directors approves the
settlement, it will be submitted to appropriate State and Federal
regulators for their approval.
Threatened and Endangered Snails
In mid-December 1992, the U.S. Fish and Wildlife Service (USFWS)
listed five species of Snake River snails as Threatened and
Endangered Species. Since that time, the Company has included
this possibility in all of its discussions regarding relicensing
and new hydro development.
The listing specifically mentions the impact that fluctuating
water levels related to hydroelectric operations may have on the
snails' habitat. Although most of the hydro facilities on that
reach of the Snake River are baseload facilities, some of them do
provide limited load-following capability. At present, there is
no certainty as to the effects, if any, that water fluctuations
caused by these facilities may have on the snails. While it is
possible that the listing could affect how Idaho Power operates
its existing hydroelectric facilities on the middle reach of the
Snake River, the Company believes that such changes will be minor
and will not present any undue hardship.
In 1995, as a part of its federal hydro relicensing process,
Idaho Power obtained a permit from the USFWS to study five
species of endangered Snake River snails. The Company's
biologists will conduct this study over the next three years,
focusing on potential snail habitat in the middle Snake River.
The Company's objective is to gain scientific insight into how
or if these snails are affected by a variety of factors,
including hydropower production, water quality, and irrigation
run-off. The study will review how these and other factors
influence the status of the various colonies and their respective
habitats.
Mountaineer Cleanup
In May 1993, the Company was notified that Bridger Coal Company
(BCC) was a potential contributor to a Superfund site involving
waste motor oil delivered to Mountaineer Refinery in Wyoming.
Idaho Energy Resources Company (IERCo), a wholly-owned subsidiary
of Idaho Power, owns one-third of BCC. In November 1993, BCC
agreed to be included on the list of parties potentially
responsible for this site. The estimated cleanup costs totaled
approximately $4.0 million. BCC's portion of the cleanup costs,
based on the amount of oil delivered to the site, was estimated
to be approximately 4.63 percent ($185,200). However, because
additional contributors are likely to be added to the list of
potentially responsible parties, BCC's final share of the cleanup
costs is likely to be considerably less. Most of the cleanup has
been completed, with the exception of a two-year program to
monitor ground water. To date, BCC has expended $84,700 in
cleanup costs and continues to carry $42,750 as an unfunded
liability as of December 31, 1995. IERCo is responsible for one-
third of BCC's share of the cleanup costs.
Clean Air
Idaho Power has analyzed the Clean Air Act's effects on the
Company and its ratepayers. The Company's coal-fired plants in
Oregon and Nevada already meet the federal emission rate
standards for sulfur dioxide (SO2) and Idaho Power's coal-fired
plant in Wyoming meets that state's even more stringent SO2
regulations. Therefore, the Company foresees no adverse effects
on its operations with regard to SO2 emissions.
During 1994, the Company, together with PacifiCorp and Black
Hills Corporation, entered into Phase I substitution agreements
with Illinois Power Company. The agreements designate Units 1, 2,
3, and 4 of the Company's Jim Bridger thermal facility, together
with facilities owned by PacifiCorp and Black Hills Corporation,
as substitution units for Illinois Power's Baldwin #2. The
substitution agreements will allow the Company to grandfather in
less restrictive Phase I nitrous oxide emission requirements at
the Jim Bridger units. As a part of the agreements, the Company
negotiated the sale of a number of its Phase I SO2 emission
allowances to Illinois Power.
Electric and Magnetic Fields
While scientific research has yet to establish any conclusive
link between electric and magnetic fields (EMFs) and human
health, the possibility has caused public concern in the United
States and abroad. Electric and magnetic fields exist wherever
there is electric current, whether the source is a high-voltage
transmission line or the simplest of electrical household
appliances. Concerns over possible health effects have prompted
regulatory efforts in several states to limit human exposure to
EMFs. Depending on what researchers ultimately discover and any
necessary regulations, it is possible that this issue could
affect a number of industries, including electric utilities.
However, it is difficult at this time to estimate what effects,
if any, the EMF issue could have on the Company and its
operations.
Competition and Strategic Planning
Competition is increasing in the electric utility industry, due
to a variety of developments. In response, Idaho Power continues
to proceed with a strategic planning process. The goal of this
process is to anticipate and fully integrate into Company
operations any legislative, regulatory, environmental,
competitive, or technological changes. With its low energy
production costs, Idaho Power is well-positioned to enter a more
competitive environment and is taking action to preserve its low-
cost competitive advantage.
The Company believes that the future of the electric utility
industry will be characterized by the right of customers to
choose their own electric service provider. To remain successful,
Idaho Power must continue to provide value to its shareholders in
the face of this new competitive environment. The Company's
vision involves three strategies for creating this value:
selective and efficient use of capital; an enhanced customer
orientation; and innovative, efficient operations. Because future
prices for power will be determined more by market forces and
less by regulatory administration, the Company must be very
selective and efficient in the use and allocation of capital.
Idaho Power will invest in improving and expanding its core
business, in developing new opportunities beyond its current
service territory, and in continuing to develop non-regulated
opportunities consistent with the Company's core competencies.
Based on this vision and the Company's efforts to increase
shareholder and customer value, Idaho Power is transforming its
operations to improve both efficiency and customer service. Teams
of employees are redesigning work processes. In some cases, these
improved processes are successfully in place. During 1995, Idaho
Power announced plans for voluntary and involuntary separation
packages in the event of workforce reductions resulting from its
reorganization efforts. The packages include compensation based
on years of service and address medical benefits and transition
services. The Company is reorganizing on a department-by-
department basis and anticipates that this redesign effort will
continue at least through 1996.
To accommodate this redesign effort and to implement its vision,
Idaho Power filed a new regulatory proposal with the IPUC on
August 3, 1995 (see Regulatory Settlement). The IPUC approved a
Settlement Stipulation that provides for a general rate freeze
through the end of 1999 and allows the accelerated amortization
of regulatory liabilities associated with accumulated deferred
investment tax credits (ADITCs), as necessary, to provide a
minimum return on actual year-end common equity of 11.5 percent.
The rate freeze and the accelerated amortization of regulatory
liabilities associated with ADITCs gives the Company time to
pursue and to implement its efficiency and growth initiatives
with the assurance of at least a reasonable level of financial
performance without the need to change customer prices.
Contract Cancellation
On June 3, 1994, the IPUC approved the buyout and cancellation of
a January 22, 1993 Firm Energy Sales Agreement (FESA) with
Meridian Generating Company, L. P. (MGC). The FESA was a 25-year
agreement with MGC for the output from a 54 MW natural gas-fired
combined cycle cogeneration facility located in Meridian, Idaho.
The Company estimates that the revenue requirement savings, net
of cancellation charges paid to MGC, are between $130 and $170
million.
Western Regional Transmission Association
The FERC has approved the formation of a transmission association
of western electric power suppliers and buyers. The members of
this association organized to provide one another with comparable
electricity transmission services. Idaho Power is a charter
member of the new organization, called the Western Regional
Transmission Association (WRTA). The WRTA is the first group of
its kind in the United States, and is indicative of changes
forthcoming in the electric utility industry. The primary
purposes of the WRTA will be to facilitate open access to
transmission services and to resolve related disputes. These
concerns are among the fundamental issues being addressed as the
electric utility industry becomes more competitive and less
regulated, in accordance with the National Energy Policy Act of
1992. The 43 members of the WRTA own about 70 percent of the
transmission system in the U.S. portion of the Western Systems
Coordinating Council.
FERC Proposed Rule
On March 29, 1995, the FERC issued a NOPR on Open-Access Non-
Discriminatory Transmission Services by Public and Transmitting
Utilities, and a supplemental NOPR on Recovery of Stranded Costs.
These NOPRs would require utilities owning transmission lines to
file non-discriminatory rates available to all buyers and sellers
of electricity, would require the utilities to use that tariff
for their own wholesale sales and purchases, and would allow the
utilities to recover stranded costs. In addition, the Company has
submitted to the FERC an open-access transmission tariff for its
existing transmission facilities. The Company anticipates that
the final rules could take effect in 1996.
Accounting Issues
In March 1995, the Financial Accounting Standards Board (FASB)
issued SFAS No. 121, "Accounting for the Impairment of Long-Lived
Assets and for Long-Lived Assets to be Disposed Of", which is
effective in 1996. This standard requires that long-lived assets
be reviewed for impairment whenever events or changes in
circumstances indicate that the carrying amount may not be
recoverable. An impairment loss would be recognized if the sum of
the estimated future undiscounted cash flows to be generated by
an asset is less than its carrying value. The amount of the loss
would be based on a comparison of book value to fair value. SFAS
No. 121 also amends SFAS No. 71, "Accounting for the Effects of
Certain Types of Regulation," to require write-off of a
regulatory asset if it is no longer probable that future revenues
will recover the cost of the asset. SFAS No. 121 does not affect
Idaho Power at this time. However, the Company will review the
standard on an ongoing basis.
In October 1995, the FASB issued SFAS No. 123, "Accounting for
Stock-Based Compensation." This standard establishes a fair-value
method of accounting for stock options and other equity
instruments. It permits entities to continue applying the
intrinsic-value method included in Statements of the Accounting
Principles Board (APB-25), but requires the entities to disclose
information in accordance with SFAS 123 if they choose to
continue using the intrinsic-value method. Among the information
that entities must disclose is the pro-forma amount of net
income and earnings per share as if the fair-value method was
used. The disclosure requirements are applicable for financial
statements for fiscal years beginning after December 15, 1995.
The Company has chosen to use the APB-25 intrinsic-value method,
but has estimated compensation costs applicable to its Restricted
Stock Plan and accrued them as a compensation expense in 1995.
Relicensing of Hydroelectric Projects
Idaho Power is actively pursuing the relicensing of its
hydroelectric projects, a process that will continue for the next
10 to 15 years. The Company submitted its first applications for
license renewal to the FERC in December 1995. These first
applications seek renewal of the Company's licenses for its
Bliss, Upper Salmon Falls, and Lower Salmon Falls Hydroelectric
Projects. Although various federal requirements and issues must
be resolved through the relicensing process, the Company
anticipates that its efforts will be successful. At this point,
however, the Company cannot predict what type of environmental or
operational requirements it may face, nor can it estimate the
eventual cost of relicensing.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO FINANCIAL STATEMENTS
AND FINANCIAL STATEMENT SCHEDULES
PAGE
Management's Responsibility for Financial Statements 41
Consolidated Financial Statements:
Consolidated Balance Sheets as of December 31, 1995,
1994 and 1993 42-43
Consolidated Statements of Income for the Years
Ended December 31, 1995, 1994 and 1993 44
Consolidated Statements of Retained Earnings for
the Years Ended December 31, 1995, 1994 and 1993 45
Consolidated Statements of Capitalization as of
December 31, 1995, 1994 and 1993 46
Consolidated Statements of Cash Flows for the Years
Ended December 31, 1995, 1994 and 1993 47
Notes to Consolidated Financial Statements 48-58
Independent Auditors' Report 59
Supplemental Financial Information (Unaudited) 60
Supplemental Schedule for the Years Ended December 31,
1995, 1994 and 1993:
Schedule II- Consolidated Valuation and
Qualifying Accounts 67
MANAGEMENT'S RESPONSIBILITY FOR FINANCIAL STATEMENTS
The management of Idaho Power Company is responsible for the
preparation and presentation of the information and
representations contained in the accompanying financial
statements. The financial statements have been prepared in
conformance with generally accepted accounting principles for a
rate regulated enterprise. Where estimates are required to be
made in preparing the financial statements, management has
applied its best judgment as to the adequacy of the estimates
based upon all available information.
The Company maintains systems of internal accounting controls and
related policies and procedures. The systems are designed to
provide reasonable assurance that all assets are protected
against loss or unauthorized use. Also, the systems provide that
transactions are executed in accordance with management's
authorization and properly recorded to permit preparation of
reliable financial statements. The systems are supported by a
staff of corporate accountants and internal auditors who, among
other duties, evaluate and monitor the systems of internal
accounting control in coordination with the independent auditors.
The staff of internal auditors conduct special and operational
audits in support of these accounting controls throughout the
year.
The Board of Directors, through its Audit Committee comprised
entirely of outside directors, meets periodically with
management, internal auditors and the Company's independent
auditors to discuss auditing, internal control and financial
reporting matters. To ensure their independence, both the
internal auditors and independent auditors have full and free
access to the Audit Committee.
The financial statements have been audited by Deloitte & Touche
LLP, the Company's independent auditors, who were responsible for
conducting their audit in accordance with generally accepted
auditing standards.
/s/ Joseph W. Marshall /s/ J. LaMont Keen
Joseph W. Marshall J. LaMont Keen
Chairman and Vice President and Chief
Chief Executive Officer Financial Officer
/s/ Harold J. Hochhalter
Harold J. Hochhalter
Controller and Chief Accounting Officer
IDAHO POWER COMPANY
CONSOLIDATED BALANCE SHEETS
ASSETS
December 31,
1995 1994 1993
(Thousands of Dollars)
ELECTRIC PLANT (Notes 1, 5 and 10):
In service (at original cost) $2,481,830 $2,383,898 $2,249,723
Accumulated provision for depreciation (830,615) (775,033) (728,979)
In service - Net 1,651,215 1,608,865 1,520,744
Construction work in progress 20,564 46,628 92,682
Held for future use 1,106 1,150 2,958
Electric plant - Net 1,672,885 1,656,643 1,616,384
INVESTMENTS AND OTHER PROPERTY 16,826 18,034 20,772
CURRENT ASSETS:
Cash and cash equivalents (Note 1) 8,468 7,748 8,228
Receivables:
Customer 33,357 31,889 29,741
Allowance for uncollectible accounts (1,397) (1,377) (1,377)
Notes 5,134 4,962 5,616
Employee notes receivable 4,648 5,444 5,909
Other 10,770 4,316 1,858
Accrued unbilled revenues (Note 1) 25,025 29,115 25,583
Materials and supplies
(at average cost) 25,937 24,141 23,372
Fuel stock (at average cost) 13,063 11,310 11,553
Prepayments (Note 9) 20,778 21,398 20,975
Regulatory assets associated
with income taxes (Note 1) 5,777 5,674 4,914
Total current assets 151,561 144,620 136,372
DEFERRED DEBITS:
American Falls and Milner water rights 32,440 32,605 32,755
Company-owned life insurance (Note 9) 56,066 49,510 45,294
Regulatory assets associated with
income taxes (Note 1) 200,379 179,311 171,569
Regulatory assets - other (Note 1) 68,348 67,713 35,036
Other 43,248 43,380 39,235
Total deferred debits 400,481 372,519 323,889
TOTAL $2,241,753 $2,191,816 $2,097,417
The accompanying notes are an integral part of these statements.
IDAHO POWER COMPANY
CONSOLIDATED BALANCE SHEETS
CAPITALIZATION AND LIABILITIES
December 31,
1995 1994 1993
(Thousands of Dollars)
CAPITALIZATION (See Page 44):
Common stock equity (Note 3):
Common stock - $2.50 par value
(shares authorized 50,000,000;
shares outstanding 1995 -
37,612,351, 1994 - 37,612,351
and 1993 - 37,085,055 $ 94,031 $ 94,031 $ 92,713
Premium on capital stock 363,044 363,063 350,882
Capital stock expense (4,127) (4,132) (4,128)
Retained earnings 229,827 220,838 222,900
Total common stock equity 682,775 673,800 662,367
Preferred stock (Note 4) 132,181 132,456 132,751
Long-term debt (Note 5) 672,618 693,206 693,780
Total capitalization 1,487,574 1,499,462 1,488,898
CURRENT LIABILITIES:
Long-term debt due within one year 20,517 517 466
Notes payable (Note 7) 53,020 55,000 4,000
Accounts payable 40,483 32,063 31,912
Taxes accrued 15,409 16,394 15,452
Interest accrued 14,785 14,755 14,920
Accumulated deferred income taxes
(Notes 1 & 2) 5,777 5,674 4,914
Other 12,866 12,574 13,731
Total current liabilities 162,858 136,977 85,395
DEFERRED CREDITS:
Regulatory liabilities associated
with accumulated deferred
investment tax credits (Notes
1 and 2) 70,507 71,593 72,013
Accumulated deferred income taxes
(Notes 1 and 2) 408,394 375,252 353,366
Regulatory liabilities associated
with income taxes (Note 1) 34,554 35,090 34,968
Regulatory liabilities - other
(Note 1) 789 626 4,235
Other (Note 9) 77,076 72,816 58,542
Total deferred credits 591,321 555,377 523,124
COMMITMENTS AND CONTINGENT
LIABILITIES (Note 8)
TOTAL $2,241,753 $2,191,816 $2,097,417
The accompanying notes are an integral part of these statements.
IDAHO POWER COMPANY
CONSOLIDATED STATEMENTS OF INCOME
Year Ended December 31,
1995 1994 1993
(Thousands of Dollars)
REVENUES (Note 1) $545,621 $543,658 $540,402
EXPENSES:
Operation:
Purchased power (Notes 8 and 10) 54,586 60,216 45,361
Fuel expense (Note 10) 54,691 94,888 87,855
Power cost adjustment (Note 1) 7,292 (12,076) (1,551)
Other 126,714 123,328 122,803
Maintenance 35,953 43,490 43,136
Depreciation (Note 1) 67,415 60,202 58,724
Taxes other than income taxes 22,979 23,945 22,129
Total expenses 369,630 393,993 378,457
INCOME FROM OPERATIONS 175,991 149,665 161,945
OTHER INCOME:
Allowance for equity funds used
during construction (Note 1) (16) 1,680 3,060
Other - Net 14,372 10,480 9,924
Total other income 14,356 12,160 12,984
INTEREST CHARGES:
Interest on long-term debt 51,146 51,172 53,706
Other interest (Notes 1 and 7) 5,309 3,261 2,750
Total interest charges 56,456 54,433 56,456
Allowance for borrowed funds used during
construction (Note 1) (1,442) (1,781) (2,465)
Net interest charges 55,014 52,652 53,991
INCOME BEFORE INCOME TAXES 135,333 109,173 120,938
INCOME TAXES (Notes 1 and 2) 48,412 34,243 36,474
NET INCOME 86,921 74,930 84,464
Dividends on preferred stock (Note 4) 7,991 7,398 6,009
EARNINGS ON COMMON STOCK $ 78,930 $ 67,532 $ 78,455
AVERAGE COMMON SHARES
OUTSTANDING (000) 37,612 37,499 36,675
EARNINGS PER SHARE OF
COMMON STOCK (Note 3) $ 2.10 $ 1.80 $ 2.14
The accompanying notes are an integral part of these statements.
IDAHO POWER COMPANY
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
Year Ended December 31,
1995 1994 1993
(Thousands of Dollars)
RETAINED EARNINGS
Beginning of year $220,838 $222,900 $212,404
NET INCOME 86,921 74,930 84,464
Total 307,759 297,830 296,868
DIVIDENDS:
Preferred stock (Note 4) 7,991 7,398 6,009
Common stock (per share:
1995 - 1993 - $1.86) (Note 3) 69,941 69,594 67,959
Total dividends 77,932 76,992 73,968
RETAINED EARNINGS
End of year $229,827 $220,838 $222,900
The accompanying notes are an integral part of these statements.
IDAHO POWER COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION
December 31,
1995 % 1994 % 1993 %
(Thousands of Dollars)
COMMON STOCK EQUITY (Note 3):
Common stock $ 94,031 $ 94,031 $ 92,713
Premium on capital stock 363,044 363,063 350,882
Capital stock expense (4,127) (4,132) (4,128)
Retained earnings 229,827 220,838 222,900
Total common stock equity 682,775 46 673,800 45 662,367 44
PREFERRED STOCK (Note 4):
4% preferred stock 17,181 17,456 17,751
7.68% Series, serial preferred
stock 15,000 15,000 15,000
8.375% Series, serial preferred
stock 25,000 25,000 25,000
Auction rate preferred stock 50,000 50,000 50,000
7.07% Series, serial
preferred stock 25,000 25,000 25,000
Total preferred stock 132,181 9 132,456 9 132,751 9
LONG-TERM DEBT (Note 5):
First mortgage bonds:
5 1/4 % Series due 1996 20,000* 20,000 20,000
5.33 % Series due 1998 30,000 30,000 30,000
8.65 % Series due 2000 80,000 80,000 80,000
6.40 % Series due 2003 80,000 80,000 80,000
8 % Series due 2004 50,000 50,000 50,000
9.50 % Series due 2021 75,000 75,000 75,000
7.50 % Series due 2023 80,000 80,000 80,000
8 3/4 % Series due 2027 50,000 50,000 50,000
9.52 % Series due 2031 25,000 25,000 25,000
Total first mortgage bonds 490,000 490,000 490,000
*Amount due within one year (20,000) - -
Net first mortgage bonds 470,000 490,000 490,000
Pollution control revenue bonds:
5.90 % Series due 2003 24,200* 24,650* 25,050*
6.0 % Series due 2007 24,000 24,000 24,000
7 1/4 % Series due 2008 4,360 4,360 4,360
7 5/8 % Series 1983 - 1984
due 2013 - 2014 68,100 68,100 68,100
8.30 % Series 1984 due 2014 49,800 49,800 49,800
Total pollution control
revenue bonds 170,460 170,910 171,310
*Amount due within one year (450) (450) (400)
Net pollution control revenue
bonds 170,010 170,460 170,910
REA notes 1,700 1,768 1,834
Amount due within one year (67) (67) (66)
Net REA notes 1,633 1,701 1,768
American Falls bond guarantee 20,740 20,905 21,055
Milner Dam note guarantee 11,700 11,700 11,700
Unamortized premium/discount-
Net (Note 1) (1,466) (1,560) (1,653)
Total long-term debt 672,618 45 693,206 46 693,780 47
TOTAL CAPITALIZATION $1,487,574 100 $1,499,462 100 $1,488,898 100
The accompanying notes are an integral part of these statements.
IDAHO POWER COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Ended December 31,
1995 1994 1993
(Thousands of Dollars)
OPERATING ACTIVITIES:
Cash received from operations:
Retail revenues $468,821 $457,202 $434,625
Wholesale revenues 59,260 62,110 84,726
Other revenues 22,825 23,711 23,411
Fuel paid (61,741) (94,530) (83,885)
Purchased power paid (52,526) (62,592) (50,246)
Other operation & maintenance paid (154,209) (171,774) (162,014)
Interest pd. (incl. long and short-term
debt only) (54,303) (52,376) (56,348)
Income taxes paid (40,402) (16,518) (32,512)
Taxes other than income taxes paid (22,939) (21,698) (22,165)
Other operating cash receipts and payments
- Net 3,644 2,122 8,213
Net cash provided by operating activities 168,430 125,657 143,805
FINANCING ACTIVITIES:
First mortgage bonds issued - - 188,136
PC bond fund requisitions/other long-term debt - - 5,594
Common stock issued - 13,402 26,781
Preferred stock issued - - 24,781
Short-term borrowings - Net (2,000) 51,000 (2,140)
Long-term debt retirement (519) (466) (191,878)
Preferred stock retirement (151) (166) (65)
Dividends on preferred stock (7,888) (7,565) (5,914)
Dividends on common stock (69,967) (69,594) (67,959)
Other sources (781) - -
Net cash - financing activities (81,306) (13,389) (22,664)
INVESTING ACTIVITIES:
Additions to utility plant (83,965) (110,523) (122,949)
Conservation (5,688) (6,830) (6,687)
Other 3,249 4,605 11,757
Net cash - investing activities (86,404) (112,748) (117,879)
Change in cash and cash equivalents 720 (480) 3,262
Cash and cash equivalents beginning of year 7,748 8,228 4,966
Cash and cash equivalents end of year $ 8,468 $ 7,748 $ 8,228
RECONCILIATION OF NET INCOME TO NET
CASH PROVIDED BY OPERATING
ACTIVITIES:
Net income $ 86,921 $ 74,930 $ 84,464
Adjustments to reconcile net income to net cash:
Depreciation 67,415 60,202 58,724
Deferred income taxes 11,539 14,265 5,997
Investment tax credit - Net (1,086) (1,064) (1,583)
Allowance for funds used during construction (1,425) (3,461) (5,525)
Postretirement benefits funding
(excl pensions) (2,857) (5,182) (7,481)
Changes in operating assets and liabilities:
Accounts receivable 5,285 (635) 2,360
Fuel inventory (7,050) 358 3,970
Accounts payable 2,061 (2,376) (4,885)
Taxes payable (2,519) 7,296 (1,141)
Interest payable 2,100 1,656 (1,010)
Other - Net 8,046 (20,332) 9,915
Net cash provided by operating activities $168,430 $125,657 $143,805
The accompanying notes are an integral part of these statements.
IDAHO POWER COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
PRINCIPLES OF CONSOLIDATION - The consolidated financial statements
include the accounts of the Company and its wholly-owned subsidiaries,
Idaho Energy Resources Co (IERCo), Ida-West Energy Company (Ida-West),
IDACORP, Inc., Idaho Utility Products Company (IUPCo), and Stellar
Dynamics. All significant intercompany transactions and balances have
been eliminated in consolidation.
SYSTEM OF ACCOUNTS - The Company is an electric utility and its
accounting records conform to the Uniform System of Accounts prescribed
by the Federal Energy Regulatory Commission (FERC) and adopted by the
public utility commissions of Idaho, Oregon, Nevada and Wyoming.
ELECTRIC PLANT - The cost of additions to electric plant in service
represents the original cost of contracted services, direct labor and
material, allowance for funds used during construction and indirect
charges for engineering, supervision and similar overhead items.
Maintenance and repairs of property and replacements and renewals of
items determined to be less than units of property are charged to
operations. For property replaced or renewed the original cost plus
removal cost less salvage is charged to accumulated provision for
depreciation while the cost of related replacements and renewals is
added to electric plant.
ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION (AFDC) - The allowance, a
non-cash item, represents the composite interest costs of debt, shown
as a reduction to interest charges, and a return on equity funds, shown
as an addition to other income, used to finance construction. While
cash is not realized currently from such allowance, it is realized
under the ratemaking process over the service life of the related
property through increased revenues resulting from higher rate base and
higher depreciation expense. Based on the uniform formula adopted by
the FERC, the Company's weighted average monthly AFDC rates for 1995,
1994 and 1993 were 6.1 percent, 8.2 percent and 9.6 percent,
respectively.
REVENUES - In order to match revenues with associated expenses, the
Company accrues unbilled revenues for electric services delivered to
customers but not yet billed at month-end.
POWER COST ADJUSTMENT- The Company has in place, in its Idaho
jurisdiction, a Power Cost Adjustment (PCA) mechanism which allows
Idaho's retail customer rates to be adjusted annually to reflect the
Idaho share of forecasted net power supply costs. Deviations from
forecasted costs are deferred with interest and then adjusted (trued-
up) in the subsequent year.
DEPRECIATION - All electric plant is depreciated using the straight-
line method. Annual depreciation provisions as a percent of average
depreciable electric plant in service approximated 2.90 percent in
1995, 2.93 percent in 1994 and 2.92 percent in 1993 and are considered
adequate to amortize the original cost over the estimated service lives
of the properties.
INCOME TAXES - The Company follows the liability method of computing
deferred taxes on all temporary differences between book and tax basis
of assets and liabilities and adjust deferred tax liabilities and
assets for enacted changes in tax laws or rates. Consistent with orders
and directives of the Idaho Public Utilities Commission (IPUC), the
regulatory authority having principal jurisdiction, deferred income
taxes (commonly referred to as normalized accounting) are provided for
the difference between income tax depreciation and straight-line
depreciation on coal-fired generation facilities and properties
acquired after 1980. On other facilities, deferred income taxes are
provided for the difference between accelerated income tax depreciation
and straight-line depreciation using tax guideline lives on assets
acquired prior to 1981. Deferred income taxes are not provided for
those income tax timing differences where the prescribed regulatory
accounting methods do not provide for current recovery in rates.
Regulated enterprises are required to recognize such adjustments as
regulatory assets or liabilities if it is probable that such amounts
will be recovered from or returned to customers in future rates (see
Note 2).
The state of Idaho allows a three percent investment tax credit (ITC)
upon certain plant additions. ITC earned on regulated assets are
deferred and amortized to income over the estimated service lives of
the related properties and credits earned on non-regulated assets or
investments are recognized in the year earned.
In 1995, the Company received an accounting order from the IPUC
approving acceleration of amortization of up to $30.0 million of
regulatory liabilities associated with deferred ITC to non-operating
income subject to Internal Revenue Service (IRS) and the Idaho State
Tax Commission (STC) approvals. The IRS application for approval has
been filed and the STC has approved the application. Acceleration of
ITC amortization is to be utilized until the actual return on year-end
common equity is 11.5 percent. No accelerated ITC was recognized in
1995.
CASH AND CASH EQUIVALENTS - For purposes of reporting cash flows, cash
and cash equivalents include cash on hand and highly liquid temporary
investments with original maturity dates of three months or less.
REGULATION OF UTILITY OPERATIONS - The Company follows Statement of
Accounting Standards (SFAS) No. 71, "Accounting for the Effects of
Certain Types of Regulation", and its financial statements reflect the
effects of the different ratemaking principles followed by the various
jurisdictions regulating the Company. Pursuant to SFAS No. 71 the
Company capitalizes, as deferred regulatory assets, incurred costs
which are expected to be recovered in future utility rates. The Company
also records as deferred regulatory liabilities the current recovery in
utility rates of costs which are expected to be paid in the future.
The following is a breakdown of regulatory assets and liabilities for
the years 1995, 1994 and 1993:
1995 1994 1993
Assets Liabilities Assets Liabilities Assets Liabilities
(Millions of Dollars)
Income taxes $206.2 $ 34.6 $185.0 $ 35.1 $176.5 $ 35.0
Conservation 36.3 29.7 21.2
Employee benefits 8.3 9.5 7.4
Other 23.7 0.7 28.5 0.6 6.4 4.2
Accumulated
deferred investment
tax credits 70.5 71.6 72.0
Total $274.5 $105.8 $252.7 $107.3 $211.5 $111.2
The regulatory environment is becoming more complex resulting from the
expanding effects of competition. In the event that recovery of cost
through rates becomes unlikely or uncertain, this may force the Company
away from the cost of service ratemaking and SFAS No. 71 would no
longer apply. If the Company were to discontinue application of SFAS
No. 71 for some or all of its operations then these items may represent
stranded investments. Certain regulators are currently reviewing ways
to allow the electric utilities to recover these investments in the
event the customers are allowed to choose their energy supplier.
However, if the Company is not allowed recovery of these investments it
would be required to write off the applicable portion of regulatory
assets and the financial effects could be significant. At December 31,
1995, the Company had $17.6 million of regulatory assets that were not
earning a return on investment excluding the $206.2 million that
relates to income taxes.
OTHER ACCOUNTING POLICIES - Debt discount, expense and premium are
being amortized over the terms of the respective debt issues.
RECLASSIFICATIONS - Certain items previously reported for years prior
to 1995 have been reclassified to conform with the current year's
presentation. Net income was not affected by these reclassifications.
2. INCOME TAXES:
1995 1994 1993
(Thousands of Dollars)
A reconciliation between the
statutory federal income tax rate
and the effective rate is as follows:
Computed income taxes based on
statutory federal income tax rate $ 47,367 $ 38,210 $ 42,328
Change in taxes resulting from:
AFUDC (504) (1,211) (1,798)
Investment tax credits (2,837) (3,351) (2,898)
Repair allowance (3,150) (1,575) (2,975)
Elimination of amounts provided
in prior years (1,963) (2,607) (4,686)
Current state income taxes 3,275 1,496 2,693
Depreciation 5,493 2,812 4,116
Other 731 469 (306)
Total provision for federal and state
income taxes $ 48,412 $ 34,243 $ 36,474
Effective tax rate 35.8% 31.4% 30.2%
The provision for income taxes consists of the following:
Income taxes currently payable:
Federal $ 33,456 $ 19,617 $ 27,892
State 4,503 1,425 4,168
Total 37,959 21,042 32,060
Income taxes deferred - Net of amortization:
Federal 10,904 12,595 5,928
State 635 1,670 69
Total 11,539 14,265 5,997
Investment and other tax credits:
Deferred 1,751 1,643 1,315
Restored (2,837) (2,707) (2,898)
Total (1,086) (1,064) (1,583)
Total provision for income taxes $ 48,412 $ 34,243 $ 36,474
The tax effects of significant items comprising the
Company's net deferred tax liability are as follows:
Deferred tax Liabilities:
Property, plant and equipment $237,655 $225,444 $217,343
Regulatory asset 206,156 184,986 176,483
Investment tax credit 70,507 71,593 72,013
Conservation programs 11,746 4,704 2,739
Other 18,489 17,811 11,384
Total 544,553 504,538 479,962
Deferred tax assets:
Regulatory liability 34,554 35,090 34,968
Advances for construction 14,823 10,542 8,103
Other 10,498 6,387 6,598
Total 59,875 52,019 49,669
Net deferred tax liabilities $484,678 $452,519 $430,293
The Company has settled Federal and Idaho tax liabilities on all open
years through the 1992 tax year except for amounts related to a
partnership which, in management's opinion, have been adequately
accrued for.
3. COMMON STOCK:
Changes in shares of the common stock of the Company for 1995, 1994 and
1993 were as follows:
Common Stock
$2.50 Par Premium on
Shares Value Capital Stock
(Thousands of Dollars)
Balance at December 31, 1992 36,186,527 $90,466 $326,338
Gain on reacquired 4% preferred
stock (Note 4) - - 50
Stock purchase plans 898,528 2,247 24,494
Balance at December 31, 1993 37,085,055 92,713 350,882
Gain on reacquired 4% preferred
stock (Note 4) - - 126
Stock purchase plans 527,296 1,318 12,055
Balance at December 31, 1994 37,612,351 94,031 363,063
Gain on reacquired 4% preferred
stock (Note 4) - - 117
Restricted Stock Plan (Note 9) - - (136)
Balance at December 31, 1995 37,612,351 $94,031 $363,044
During the period of January 1993 through May 1994, the Company issued
original issue shares of common stock for its Dividend Reinvestment and
Stock Purchase Plan and the Employee Savings Plan. During 1993 and 1994
common shares totaling 898,528 and 527,296 respectively, were issued to
these plans.
As of December 31, 1995, the Company had 2,791,321 of its authorized
but unissued shares of common stock reserved for future issuance under
its Dividend Reinvestment and Stock Purchase Plan and Employee Savings
Plan.
On January 11, 1990, the Board of Directors adopted a Shareowner Rights
Plan (Plan). Under the Plan, the Company declared a distribution of one
Preferred Stock Right (Right) for each of the Company's outstanding
Common shares held on January 29, 1990 or issued thereafter. The Rights
are currently not exercisable and will be exercisable only if a person
or group (Acquiring Person) either acquires ownership of 20 percent or
more of the Company's Voting Stock or commences a tender offer that
would result in ownership of 20 percent or more. The Company may redeem
the Rights at a price of $0.01 per Right anytime prior to acquisition
by an Acquiring Person of a 20 percent position.
Following the acquisition of a 20 percent position, each Right will
entitle its holder, subject to regulatory approval, to purchase for $85
that number of shares of Common Stock or Preferred Stock having a
market value of $170.
If after the Rights become exercisable, the Company is acquired in a
merger or other business combination, 50 percent or more of its
consolidated assets or earnings power are sold or the Acquiring Person
engages in certain acts of self-dealing, each Right entitles the holder
to purchase for $85, shares of the acquiring company's Common Stock
having a market value of $170. Any Rights that are or were held by an
Acquiring Person become void if either of these events occurs. The
Rights expire on January 11, 2000.
4. PREFERRED STOCK:
The number of shares of preferred stock outstanding at December 31,
1995, 1994 and 1993 were as follows:
Shares Outstanding at
December 31, Call Price
1995 1994 1993 Per Share
Preferred stock:
Cumulative, $100 par value:
4% preferred stock (authorized
215,000 shares) 171,813 174,556 177,506 $104.00
Serial preferred stock, 7.68%
Series (authorized 150,000
shares) 150,000 150,000 150,000 $102.97
Serial preferred stock, cumulative,
without par value; total of
3,000,000 shares authorized:
8.375% Series, $100 stated value,
(authorized 250,000 shares)(a) 250,000 250,000 250,000 $105.58
to $100.37
7.07% Series, $100 stated value,
(authorized 250,000 shares)(b) 250,000 250,000 250,000 $103.535
to $100.354
Auction rate preferred stock,
$100,000 stated value,
(authorized 500 shares)(c) 500 500 500 $100,000.00
Total 822,313 825,056 828,006
(a) Not redeemable prior to October 1, 1996.
(b) Not redeemable prior to July 1, 2003.
(c) Dividend rate at December 31, 1995 was 4.49% and ranged between
4.36% and 4.71% during the year.
During 1995, 1994 and 1993 the Company reacquired and retired 2,743;
2,950 and 1,229 shares of 4% preferred stock resulting in a net
addition to premium on capital stock of $117,346, $126,066 and $50,151
respectively. As of December 31, 1995 the overall effective cost of all
outstanding preferred stock was 6.28 percent.
5. LONG-TERM DEBT:
The amount of first mortgage bonds issuable by the Company is limited
to a maximum of $900,000,000 and by property, earnings and other
provisions of the mortgage and supplemental indentures thereto.
Substantially all of the electric utility plant is subject to the lien
of the indenture. Pollution Control Revenue Bonds, Series 1984, due
December 1, 2014, are secured by First Mortgage Bonds, Pollution
Control Series A, which were issued by the Company and are held by a
Trustee for the benefit of the bondholders.
First mortgage bonds maturing during the five-year period ending 2000
are $20,000,000 in 1996, $30,000,000 in 1998 and $80,000,000 in 2000.
Sinking fund requirements for the first mortgage bonds outstanding at
December 31, 1995 are $5,398,000 per year. These requirements may be
met by the deposit of cash, deposit of bonds, or by certification of
property additions at the rate of 167% of requirements. The Company's
practice is to certify additional property to meet the sinking fund
requirements. In September 1993, 1994, and 1995 $400,000, $400,000 and
$450,000 respectively, of the 5.90% Series, Pollution Control Revenue
Bonds, were retired pursuant to sinking fund requirements for those
years. Sinking fund requirements during the five-year period ending
2000 for pollution control bonds outstanding at December 31, 1995 are
$450,000 in 1996 and $500,000 in 1997 through 2000. At December 31,
1993, 1994 and 1995, the overall effective cost of all outstanding
first mortgage bonds and pollution control revenue bonds for all three
years was 8.02 percent.
6. FAIR VALUE OF FINANCIAL INSTRUMENTS:
The estimated fair value of the Company's financial instruments have
been determined by the Company using available market information and
appropriate valuation methodologies. The use of different market
assumptions and/or estimation methodologies may have a material effect
on the estimated fair value amounts.
Cash and cash equivalents, customer and other receivables, notes
payable, accounts payable, interest accrued, and taxes accrued are
reported at their carrying value as these are a reasonable estimate of
their fair value. The total estimated fair value of long-term debt was
approximately $762,575,000 for 1993, $682,647,000 for 1994 and
$731,168,000 for 1995. The estimated fair values for long-term debt are
based upon quoted market prices of the same or similar issues.
7. NOTES PAYABLE:
At January 1, 1996, the Company had regulatory authority to incur up to
$150,000,000 of short-term indebtedness. Under this authority, total
lines of credit maintained with various banks amounted to $85,000,000.
Under annual borrowing arrangements with these banks, the Company is
required to pay a fee of 8/100 of 1 percent on the available and
committed lines of credit. Commercial paper may be issued in an amount
not to exceed 25 percent of revenues for the latest twelve-month period
subject to the $150,000,000 maximum described above and are supported
by bank lines of credit of an equal amount.
Balances and interest rates of short-term borrowings were as follows:
Year Ended December 31,
1995 1994 1993
(Thousands of Dollars)
Balance at end of year $53,020 $55,000 $4,000
Effective annual interest rate
at end of year 6.0% 6.1% 6.9%
(a) Effective rate has been inflated by the commitment fees being
larger than the interest paid for the year.
If the commitment fees were excluded the effective annual interest
rate at end of the year would have been 3.6%.
8. COMMITMENTS AND CONTINGENT LIABILITIES:
Commitments under contracts and purchase orders relating to the
Company's program for construction and operation of facilities amounted
to approximately $2,600,000 at December 31, 1995. The commitments are
generally revocable by the Company subject to reimbursement of
manufacturers' expenditures incurred and/or other termination charges.
The Company is currently purchasing energy from 65 on-line cogeneration
and small power production facilities with contracts ranging from 1 to
32 years. Under these contracts the Company could be required to
purchase up to 782,000 (MWH) annually. During the fiscal year ended
December 31, 1995, the Company purchased 654,000 (MWH) at a cost of
$38.0 million.
The Company is party to various legal claims, actions, and complaints,
certain of which involve material amounts. Although the Company is
unable to predict with certainty whether or not it will ultimately be
successful in these legal proceedings, or, if not, what the impact
might be, based upon the advice of legal counsel, management presently
believes that disposition of these matters will not have a material
adverse effect on the Company's financial position, results of
operation or cash flow.
9. BENEFIT PLANS:
Incentive Plan - The Company implemented two annual incentive plans
effective January 1, 1995. The Executive Annual Incentive Plan and the
Employee Incentive Plan tie a portion of each employee's compensation
to achieving annual operational and financial goals. The plans share
common goals designed to promote safety, control capital expenditures,
control operation and maintenance expenses and increase annual earnings
per share. At December 31, 1995 the Company had recorded $2,898,785 of
incentive for the Plans.
Restricted Stock Plan - The 1994 Restricted Stock Plan ("Plan")
approved by shareholders at the May 1994 Annual Meeting was implemented
January 1, 1995 as an equity-based long-term incentive plan. The
performance-based grant approach and administrative guidelines for the
Plan were developed by the Compensation Committee of the Board of
Directors ("Committee") during 1994. At December 31, 1995, there were
370,000 shares reserved for the Plan. The first grant under the Plan
was made to all officers during January 1995. For the first grant, the
Committee has selected a three-year restricted period beginning January
1, 1995, through December 31, 1997, with a single financial performance
goal of Cumulative Earnings Per Share ("CEPS"). Final award amounts
will depend on the attainment by the Company of the CEPS performance
goal established by the Committee and may be prorated in the event of
death, disability or retirement of an officer based on the number of
whole months of service the officer completes during the Restricted
Period. Upon the officer's termination of employment during the
Restricted Period for any other reason, all such shares will be
forfeited by the officer to the Trustee.
During 1995, the Company purchased and granted 9,480 shares of the
Company's common stock for this Plan. Of this amount 360 shares were
forfeited in 1995. Restricted stock awards are compensatory awards and
the Company accrued compensation expense of $91,200 for 1995 (which was
charged to operations) based upon the market value of the earned
shares.
Pension Plan - The Company maintains a trusteed noncontributory defined
benefit pension plan for all employees who work 1,000 hours or more
during a calendar year. The benefits under the plan are based on years
of service and the employee's final average earnings. The Company's
policy is to fund with an independent corporate trustee at least the
minimum required under the Employee Retirement Income Security Act of
1974 but not more than the maximum amount deductible for income tax
purposes. The Company funded $5.9 million in 1995, $5.5 million in 1994
and $5.0 million in 1993. The plan's assets held by the trustee consist
primarily of listed stocks (both U.S. and foreign), fixed income
securities and investment grade real estate.
Deferred Compensation Plan - The Company has a nonqualified, deferred
compensation plan for certain senior management employees and directors
that provides for supplemental retirement and death benefit payments to
the participant and his or her family. The plan is being financed by
life insurance policies, of which the Company is the beneficiary, with
premiums being paid by the Company. These policies have accumulated
cash values of $53.0, $47.1 and $42.4 million at December 31, 1995,
1994 and 1993, respectively, which do not qualify as plan assets in the
actuarial computation of the funded status. Based upon SFAS No. 87, the
Company has recorded a net liability of $21.5 million as of December
31, 1995.
The following tables set forth the amounts recognized in the Company's
financial statements and the funded status of both plans in accordance
with accounting standard SFAS No. 87, "Employers' Accounting for
Pensions."
Plan Costs for the Year: 1995 1994 1993
(Thousands of Dollars)
Pension plan:
Service cost $ 5,167 $ 6,049 $ 4,496
Interest cost 12,998 12,263 11,688
Actual return on plan assets (45,990) 312 (23,322)
Deferred gain (loss) on plan assets 31,489 (15,584) 9,848
Net cost $ 3,664 $ 3,040 $ 2,710
Approximate percentage included in
operating expenses 65% 67% 66%
Net deferred compensation plan costs
charged to other income (including
life insurance and SFAS No. 87
liability accrual)(a) $ 37 $ 508 $ 1,372
(a) These charges to the Income Statement have been reduced by
gains from the Company-Owned Life Insurance of $2,320; $2,724, and
$1,638, for 1995, 1994 and 1993, respectively.
Funded status and significant assumptions as of December 31:
Deferred
Pension Plan Compensation Plan
1995 1994 1993 1995 1994 1993
(Thousands of Dollars)
Actuarial present value of
benefit obligations:
Vested benefit obligation $145,334 $128,162 $134,292 $ 21,530 $ 19,148 $ 24,024
Accumulated benefit
obligation $150,688 $132,766 $139,270 $ 21,530 $ 19,148 $ 24,027
Projected benefit obligation $193,133 $167,103 $179,895 $ 22,111 $ 19,681 $ 30,114
Plan assets at fair value 204,760 165,839 169,920 - - -
Plan assets in excess of (or
less than) projected benefit
obligation 11,627 (1,264) (9,975) (22,111) (19,681) (30,114)
Unrecognized net (gain) loss
from past experience different
from that assumed (8,341) 6,040 17,295 4,389 2,173 7,295
Unrecognized prior service cost 5,941 6,365 1,460 (3,097) (3,516) 2,546
Unrecognized net (asset)
obligation existing at date of
initial adoption (19.5 year
straight-line amortization) (2,493) (2,756) (3,019) 5,827 6,440 7,053
Minimum liability adjustment - - - (6,538) (4,564) (10,807)
Net asset (liability) included
in the balance sheet $ 6,734 $ 8,385 $ 5,761 $(21,530) $(19,148) $(24,027)
Discount rate to compute
projected benefit obligation 7.25% 8.0% 7.0% 7.25% 8.0% 7.0%
Rate for future compensation
increases 4.5 4.5 4.5 4.5 4.5 4.5
Expected long-term rate of
return on plan assets 9.0 9.0 9.0 - - -
Supplemental Employee Retirement Plan (SERP) - The Company has a
nonqualified SERP that provides benefits in excess of Internal
Revenue Service limits (Section 401 (a) (17) of the Internal
Revenue Code) for highly paid individuals. The projected benefit
obligation of this plan was $1,581,000, $857,000 and $525,000 at
December 31, 1995, 1994 and 1993, respectively, with accrued
pension costs of $682,000, $396,000 and $226,000. The Company's
net periodic pension cost of this plan was $184,000, $125,000 and
$36,000 for the same periods.
Savings Plan - The Company has an Employee Savings Plan whereby,
for each $1 of employee contribution up to 6 percent of their
base salary the Company will match 100 percent of the first 2
percent employee contribution and 50 percent of the next 4
percent employee contribution, all such amounts to be invested by
a trustee to any or all of seven investment options. The
Company's contribution amounted to $2,426,840 in 1995, $2,410,200
in 1994 and $2,283,200 in 1993.
Postretirement Benefits - The Company maintains a defined benefit
postretirement plan (consisting of health care and life
insurance) that covers all employees who were enrolled in the
active group plan at the time of retirement, their spouses and
qualifying dependents. The plan provides for payment of hospital
services, physician services, prescription drugs, dental services
and various other health services, some of which have annual or
lifetime limits, after subtracting payments by Medicare or other
providers and after a stated deductible and co-payments have been
met. Participants become eligible for the benefits if they retire
from the Company after reaching age 55 with 15 years of service
or after 30 years of service. The plan is contributory with
retiree contributions adjusted annually. For those retirees that
were age 65 or older at December 31, 1992 the plan is
noncontributory. The Company also provides life insurance of one
times salary for pre-65 retirees and $20,000 for post-65 retirees
with the retirees paying a portion of the cost.
The following tables set forth the amounts to be recognized in
the Company's financial statements for year-end 1995, 1994 and
1993 and the funded status of the plan in accordance with
accounting standard SFAS No. 106 as of December 31:
1995 1994 1993
Postretirement Benefit Cost: (Thousands of Dollars)
Service Cost $ 763 $ 855 $ 750
Interest Cost 3,571 3,334 3,610
Actual return on plan assets (1,116) (1,114) (860)
Amortization of transition obligation
20 year amortization) 2,040 2,040 2,040
Net amortization and deferral - - -
Regulatory assets 506 (1,907) (3,548)
Voluntary severance program 64 - -
Net cost $ 5,828 $ 3,208 $ 1,992
1995 1994 1993
Funded Status: (Thousands of Dollars)
Accumulated postretirement benefit
obligation (APBO) $(48,928) $(45,001) $(48,290)
Plan assets at fair value 15,920 12,116 11,840
APBO in excess of plan assets (33,008) (32,885) (36,450)
Unrecognized gain/losses 378 773 4,670
Unrecognized transition obligation 34,680 36,720 38,760
Prepaid postretirement benefit cost $ 2,050 $ 4,608 $ 6,980
Discount rate 7.50% 8.25% 7.25%
Medical and dental inflation rate 6.75 7.25 6.75
Long-term plan assets expected return 9.0 9.0 9.0
A one percent change in the medical inflation rate would change
the APBO by 7.2 percent and the postretirement expense for 1995
by 8.6 percent.
The Company has a retiree medical benefits funding program which
consists of life insurance policies on active employees of which
the Company is the beneficiary, and a qualified Voluntary
Employees Beneficiary Association (VEBA) Trust. The net charge to
other income for the life insurance policies was $1,754,300 in
1995, $776,400 in 1994 and $632,500 in 1993. The funding to the
VEBA was $916,200 in 1995, $743,600 in 1994 and $2,692,000 in
1993 and recorded as a prepayment. The VEBA trust represents plan
assets which are invested in variable life insurance policies,
Trust Owned Life Insurance (TOLI), on active employees. Inside
buildup in the TOLI policies is tax deferred and tax free if the
policy proceeds are paid to the Trust as death benefits. The
investment return assumption reflects an expectation that
investment income in the VEBA will be substantially tax free.
Postemployment Benefits - The Company provides certain benefits
to former or inactive employees, their beneficiaries, and covered
dependents after employment but before retirement. The Company
accrues for such postemployment benefits. These benefits include
salary continuation and related health care and life insurance
for both long and short-term disability plans, workmen's
compensation and health care for surviving spouse and dependent
plan. The Company recognizes a deferred asset which represents
future revenue expected to be realized at the time the
postemployment benefits are included in the Company's rates. The
Company has recorded a liability of $3.7 million and a regulatory
asset of $3.4 million which represents the costs associated with
postemployment benefits at December 31, 1995. The Company
received IPUC Order No. 25880 authorizing the amortization of the
regulatory asset over a 10-year period.
10.ELECTRIC PLANT IN SERVICE AND JOINTLY-OWNED PROJECTS:
The following table sets out the major classifications of the
Company's electric plant in service and accumulated provision for
depreciation for the years 1995, 1994, and 1993.
Electric Plant in Service: 1995 1994 1993
(Thousands of Dollars)
Production $1,350,239 $1,303,572 $1,229,237
Transmission 330,812 308,055 298,201
Distribution 648,549 625,149 582,604
General and other 152,230 147,122 139,681
Total in service 2,481,830 2,383,898 2,249,723
Accumulated provision for
depreciation (830,615) (775,033) (728,979)
In service - Net $1,651,215 $1,608,865 $1,520,744
The Company is involved in the ownership and operation of three
jointly-owned generating facilities. The Consolidated Statements
of Income include the Company's proportionate share of direct
operation and maintenance expenses applicable to the projects.
Each facility and extent of Company participation as of December
31, 1995 are as follows:
Company Ownership
Electric Accumulated
Plant In Provision for
Name of Plant/Location Service Depreciation % MW
(Thousands of Dollars)
Jim Bridger Units 1-4
Rock Springs, WY $379,008 $159,721 33 693
Boardman
Boardman, OR 60,368 26,087 10 53
Valmy Units 1 & 2
Winnemucca, NV 299,189 105,612 50 261
The Company's wholly-owned subsidiary, IERCO, is a joint venturer
in Bridger Coal Company, which operates the mine supplying coal
for the Jim Bridger steam generation plant. Coal purchased by the
Company from the joint venture amounted to $44,278,000 in 1995,
$46,097,000 in 1994 and $45,424,000 in 1993.
The Company has contracts to purchase the energy from five PURPA
Qualified Facilities which are 50 percent owned by Ida-West.
Power purchased from these facilities amounted to $8,695,800 in
1995, $7,139,000 in 1994 and $5,975,093 in 1993.
INDEPENDENT AUDITORS' REPORT
Board of Directors and Shareowners of Idaho Power Company:
We have audited the accompanying consolidated balance sheets and
statements of capitalization of Idaho Power Company and its
subsidiaries listed in the accompanying index to financial
statements and financial statement schedules at Item 8. These
financial statements and financial schedules are the
responsibility of the Company's management. Our responsibility
is to express an opinion on the financial statements and
financial schedules 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 consolidated 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, such consolidated financial statements present
fairly, in all material respects, the consolidated financial
position of Idaho Power Company and subsidiaries at December 31,
1995, 1994, and 1993, and the results of their operations and
their cash flows for the years then ended in conformity with
generally accepted accounting principles. Also, in our opinion,
such financial statement schedule, when considered in relation
to the basic consolidated financial statements taken as a whole,
present fairly in all material respects the information set forth
therein.
Deloitte & Touche LLP
Portland, Oregon
January 31, 1996
IDAHO POWER COMPANY
SUPPLEMENTAL FINANCIAL INFORMATION, UNAUDITED
QUARTERLY FINANCIAL DATA:
The following unaudited information is presented for each quarter
of 1995, 1994 and 1993 (in thousands of dollars, except for per
share amounts). In the opinion of the Company, all adjustments
necessary for a fair statement of such amounts for such periods
have been included. The results of operation for the interim
periods are not necessarily indicative of the results to be
expected for the full year. Accordingly, earnings information for
any three month period should not be considered as a basis for
estimating operating results for a full fiscal year. Amounts are
based upon quarterly statements and the sum of the quarters may
not equal the annual amount reported.
Quarter Ended
March 31 June 30 Sept 30 Dec 31
1995
Revenues $131,336 $130,254 $148,726 $135,306
Income from operations 46,552 38,681 45,637 45,122
Income taxes 14,234 10,951 12,442 10,786
Net income 20,727 17,588 23,772 24,833
Dividends on preferred stock 2,026 2,006 1,976 1,982
Earnings on common stock 18,701 15,582 21,796 22,851
Earnings per share of common
stock 0.50 0.41 0.58 0.61
1994
Revenues 128,810 128,541 151,031 135,277
Income from operations 37,408 33,984 33,609 44,663
Income taxes 9,406 6,554 8,150 10,133
Net income 18,260 17,030 16,289 23,351
Dividends on preferred stock 1,789 1,819 1,862 1,928
Earnings on common stock 16,471 15,211 14,427 21,423
Earnings per share of common
stock 0.44 0.41 0.38 0.57
1993
Revenues 140,809 129,471 134,577 135,545
Income from operations 41,479 38,980 34,286 47,201
Income taxes 10,610 9,270 9,108 7,486
Net income 21,347 18,524 16,427 28,166
Dividends on preferred stock 1,345 1,318 1,565 1,781
Earnings on common stock 20,002 17,206 14,862 26,385
Earnings per share of common
stock 0.55 0.47 0.40 0.71
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE
None
PART III
Part III has been omitted because the registrant will file a
definitive proxy statement pursuant to Regulation 14A, which
involves the election of Directors, with the Commission within
120 days after the close of the fiscal year portions of which are
hereby incorporated by reference (except for information with
respect to executive officers which is set forth in Part I
hereof).
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULE
AND REPORTS ON FORM 8-K
(a) Please refer to Item 8, "Financial Statements and
Supplementary Data" for a complete listing of all
consolidated financial statements and financial statement
schedule.
(b) Reports on SEC Form 8-K. No reports on Form 8-K were filed
during the three months ended December 31, 1995.
(c) Exhibits.
* Previously Filed and Incorporated Herein by Reference
File As
Exhibit Number Exhibit
*3(a) 33-00440 4(a)(xiii) Restated Articles of Incorporation
of the Company as filed with the
Secretary of State of Idaho on
June 30, 1989.
*3(a)(i) 33-65720 4(a)(i) Statement of Resolution
Establishing Terms of 8.375%
Serial Preferred Stock, Without
Par Value (cumulative stated value
of $100 per share), as filed with
the Secretary of State of Idaho on
September 23, 1991.
*3(a)(ii) 33-65720 4(a)(ii) Statement of Resolution
Establishing Terms of Flexible
Auction Series A, Serial Preferred
Stock, Without Par Value
(cumulative stated value of
$100,000 per share), as filed with
the Secretary of State of Idaho on
November 5, 1991.
*3(a)(iii) 33-65720 4(a)(iii) Statement of Resolution
Establishing Terms of 7.07% Serial
Preferred Stock, Without Par Value
(cumulative stated value of $100
per share), as filed with the
Secretary of State of Idaho on
June 30, 1993.
*3(b) 33-41166 4(b) Waiver resolution to Restated
Articles of Incorporation adopted
by Shareholders on May 1, 1991.
*3(c) 33-00440 4(a)(xiv) By-laws of the Company amended on
June 30, 1989, and presently in
effect.
*4(a)(i) 2-3413 B-2 Mortgage and Deed of Trust, dated
as of October 1, 1937, between the
Company and Bankers Trust Company
and R. G. Page, as Trustees.
*4(a)(ii) Supplemental Indentures to
Mortgage and Deed of Trust:
Number Dated
1-MD B-2-a First July 1, 1939
2-5395 7-a-3 Second November 15, 1943
2-7237 7-a-4 Third February 1, 1947
2-7502 7-a-5 Fourth May 1, 1948
2-8398 7-a-6 Fifth November 1, 1949
2-8973 7-a-7 Sixth October 1, 1951
2-12941 2-C-8 Seventh January 1, 1957
2-13688 4-J Eighth July 15, 1957
2-13689 4-K Ninth November 15, 1957
2-14245 4-L Tenth April 1, 1958
2-14366 2-L Eleventh October 15, 1958
2-14935 4-N Twelfth May 15, 1959
2-18976 4-O Thirteenth November 15, 1960
2-18977 4-Q Fourteenth November 1, 1961
2-22988 4-B-16 Fifteenth September 15, 1964
2-24578 4-B-17 Sixteenth April 1, 1966
2-25479 4-B-18 Seventeenth October 1, 1966
2-45260 2(c) Eighteenth September 1, 1972
2-49854 2(c) Nineteenth January 15, 1974
2-51722 2(c)(i) Twentieth August 1, 1974
2-51722 2(c)(ii) Twenty-first October 15, 1974
2-57374 2(c) Twenty-second November 15, 1976
2-62035 2(c) Twenty-third August 15, 1978
33-34222 4(d)(iii) Twenty-fourth September 1, 1979
33-34222 4(d)(iv) Twenty-fifth November 1, 1981
33-34222 4(d)(v) Twenty-sixth May 1, 1982
33-34222 4(d)(vi) Twenty-seventh May 1, 1986
33-00440 4(c)(iv) Twenty-eighth June 30, 1989
33-34222 4(d)(vii) Twenty-ninth January 1, 1990
33-65720 4(d)(iii) Thirtieth January 1, 1991
33-65720 4(d)(iv) Thirty-first August 15, 1991
33-65720 4(d)(v) Thirty-second March 15, 1992
33-65720 4(d)(vi) Thirty-third April 1, 1993
1-3198 4 Thirty-fourth December 1, 1993
Form 8-K
Dated
12/17/93
*4(b) Instruments relating to American
Falls bond guarantee. (see
Exhibits 10(f) and 10(f)(i)).
*4(c) 33-65720 4(f) Agreement to furnish certain debt
instruments.
*4(d) 33-00440 2(a)(iii) Agreement and Plan of Merger dated
March 10, 1989, between Idaho
Power Company, a Maine
Corporation, and Idaho Power
Migrating Corporation.
*4(e) 33-65720 4(e) Rights Agreement dated January 11,
1990, between the Company and
First Chicago Trust Company of New
York, as Rights Agent (The Bank of
New York, successor Rights Agent).
*10(a) 2-51762 5(a) Agreement, dated April 20, 1973,
between the Company and FMC
Corporation.
*10(a)(i) 2-57374 5(b) Letter Agreement, dated
October 22, 1975, relating to
agreement filed as Exhibit 10(a).
*10(a)(ii) 2-62034 5(b)(i) Letter Agreement, dated
December 22, 1976, relating to
agreement filed as Exhibit 10(a).
*10(a)(iii) 33-65720 10(a) Letter Agreement, dated
December 11, 1981, relating to
agreement filed as Exhibit 10(a).
*10(b) 2-49584 5(b) Agreements, dated September 22,
1969, between the Company and
Pacific Power & Light Company
relating to the operation,
construction and ownership of the
Jim Bridger Project.
*10(b)(i) 2-51762 5(c) Amendment, dated February 1, 1974,
relating to operation agreement
filed as Exhibit 10(b).
*10(c) 2-49584 5(c) Agreement, dated as of October 11,
1973, between the Company and
Pacific Power & Light Company.
*10(d) 2-49584 5(d) Agreement, dated as of October 24,
1973, between the Company and Utah
Power & Light Company.
*10(d)(i) 2-62034 5(f)(i) Amendment, dated January 25, 1978,
relating to agreement filed as
Exhibit 10(d).
*10(e) 33-65720 10(b) Coal Purchase Contract, dated as
of June 19, 1986, among the
Company, Sierra Pacific Power
Company and Black Butte Coal
Company.
*10(f) 2-57374 5(k) Contract, dated March 31, 1976,
between the United States of
America and American Falls
Reservoir District, and related
Exhibits.
*10(f)(i) 33-65720 10(c) Guaranty Agreement, dated
March 1, 1990, between the Company
and West One Bank, as Trustee,
relating to $21,425,000 American
Falls Replacement Dam Bonds of the
American Falls Reservoir District,
Idaho.
*10(g) 2-57374 5(m) Agreement, effective April 15,
1975, between the Company and The
Washington Water Power Company.
*10(h) 2-62034 5(p) Bridger Coal Company Agreement,
dated February 1, 1974, between
Pacific Minerals, Inc., and Idaho
Energy Resources Co.
*10(i) 2-62034 5(q) Coal Sales Agreement, dated
February 1, 1974, between Bridger
Coal Company and Pacific Power &
Light Company and the Company.
*10(i)(i) 33-65720 10(d) Second Restated and Amended Coal
Sales Agreement, dated March 7,
1988, among Bridger Coal Company
and PacifiCorp (dba Pacific
Power & Light Company) and the
Company.
*10(j) 2-62034 5(r) Guaranty Agreement, dated as of
August 30, 1974, with Pacific
Power & Light Company.
*10(k) 2-56513 5(i) Letter Agreement, dated January
23, 1976, between the Company and
Portland General Electric Company.
*10(k)(i) 2-62034 5(s) Agreement for Construction,
Ownership and Operation of the
Number One Boardman Station on
Carty Reservoir, dated as of
October 15, 1976, between Portland
General Electric Company and the
Company.
*10(k)(ii) 2-62034 5(t) Amendment, dated September 30,
1977, relating to agreement filed
as Exhibit 10(k).
*10(k)(iii) 2-62034 5(u) Amendment, dated October 31, 1977,
relating to agreement filed as
Exhibit 10(k).
*10(k)(iv) 2-62034 5(v) Amendment, dated January 23, 1978,
relating to agreement filed as
Exhibit 10(k).
*10(k)(v) 2-62034 5(w) Amendment, dated February 15,
1978, relating to agreement filed
as Exhibit 10(k).
*10(k)(vi) 2-68574 5(x) Amendment, dated September 1,
1979, relating to agreement filed
as Exhibit 10(k).
*10(l) 2-68574 5(z) Participation Agreement, dated
September 1, 1979, relating to the
sale and leaseback of coal
handling facilities at the Number
One Boardman Station on Carty
Reservoir.
*10(m) 2-64910 5(y) Agreements for the Operation,
Construction and Ownership of the
North Valmy Power Plant Project,
dated December 12, 1978, between
Sierra Pacific Power Company and
the Company.
*10(n)(i)1 1-3198 10(n)(i) The Revised Security Plans for
Form 10-K Senior Management Employees and
for 1994 for Directors-a non-qualified,
deferred compensation plan
effective November 30, 1994.
_________________
1
Compensatory Plan
*10(n)(ii)1 1-3198 10(n)(ii) The Executive Annual Incentive
Form 10-K Plan for senior management
for 1994 employees effective January 1,
1995.
*10(n)(iii)1 1-3198 10(n)(iii) The 1994 Restricted Stock Plan for
Form 10-K officers and key executives
for 1994 effective July 1, 1994.
*10(o) 33-65720 10(f) Residential Purchase and Sale
Agreement, dated August 22, 1981,
among the United Stated of America
Department of Energy acting by and
through the Bonneville Power
Administration, and the Company.
*10(p) 33-65720 10(g) Power Sales Contact, dated
August 25, 1981, including
amendments, among the United
States of America Department of
Energy acting by and through the
Bonneville Power Administration,
and the Company.
*10(q) 33-65720 10(h) Framework Agreement, dated October
1, 1984, between the State of
Idaho and the Company relating to
the Company's Swan Falls and Snake
River water rights.
*10(q)(i) 33-65720 10(h)(i) Agreement, dated October 25, 1984,
between the State of Idaho and the
Company relating to the agreement
filed as Exhibit 10(q).
*10(q)(ii) 33-65720 10(h)(ii) Contract to Implement, dated
October 25, 1984, between the
State of Idaho and the Company
relating to the agreement filed as
Exhibit 10(q).
*10(r) 33-65720 10(i) Agreement for Supply of Power and
Energy, dated February 10, 1988,
between the Utah Associated
Municipal Power Systems and the
Company.
*10(s) 33-65720 10(j) Agreement Respecting Transmission
Facilities and Services, dated
March 21, 1988 among PC/UP&L
Merging Corp. and the Company
including a Settlement Agreement
between PacifiCorp and the
Company.
*10(s)(i) 33-65720 10(j)(i) Restated Transmission Services
Agreement, dated February 6, 1992,
between Idaho Power Company and
PacifiCorp.
*10(t) 33-65720 10(k) Agreement for Supply of Power and
Energy, dated February 23, 1989,
between Sierra Pacific Power
Company and the Company.
*10(u) 33-65720 10(l) Transmission Services Agreement,
dated May 18, 1989, between the
Company and the Bonneville Power
Administration.
___________________
1
Compensatory Plan
*10(v) 33-65720 10(m) Agreement Regarding the Ownership,
Construction, Operation and
Maintenance of the Milner
Hydroelectric Project (FERC No.
2899), dated January 22, 1990,
between the Company and the Twin
Falls Canal Company and the
Northside Canal Company Limited.
*10(v)(i) 33-65720 10(m)(i) Guaranty Agreement, dated February
10, 1992, between the Company and
New York Life Insurance Company,
as Note Purchaser, relating to
$11,700,000 Guaranteed Notes due
2017 of Milner Dam Inc.
*10(w) 33-65720 10(n) Agreement for the Purchase and
Sale of Power and Energy, dated
October 16, 1990, between the
Company and The Montana Power
Company.
*10(x) 1-3198 10(x) Agreement for design of substation
Form 10-Q dated October 4, 1995, between the
for 9/30/95 Company and Micron Technology,
Inc.
12 Statement Re: Computation of
Ratio of Earnings to Fixed
Charges.
12(a) Statement Re: Computation of
Supplemental Ratio of Earnings to
Fixed Charges.
12(b) Statement Re: Computation of
Ratio of Earnings to Combined
Fixed Charges and Preferred
Dividend Requirements.
12(c) Statement Re: Computation of
Supplemental Ratio of Earnings to
Combined Fixed Charges and
Preferred Dividend Requirements.
*21 1-3198 21 Subsidiaries of Registrant
Form 10-K
for 1994
23 Independent Auditors' Consent.
27 Financial Data Schedule
IDAHO POWER COMPANY
SCHEDULE II - CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
Years Ended December 31, 1995, 1994 and 1993
Column A Column B Column C Column D Column E
Additions
Charged Balance
Balance At Charged (Credited) At
Beginning to to Other Deductions End Of
Classification Of Period Income Accounts (1) Period
(Thousands of Dollars)
1995:
Reserves Deducted From
Applicable Assets:
Reserve for
uncollectible
accounts $1,377 $ 217 $2,927(2) $3,124 $1,397
Other Reserves:
Injuries and damages
reserve $1,500 $1,364 $ - $1,364 $1,500
Miscellaneous
operating reserves $ 940 $ 460 $ (176) $ 81 $1,143
1994:
Reserves Deducted From
Applicable Assets:
Reserve for
uncollectible
accounts $1,377 $1,360 $1,018(2) $2,378 $1,377
Other Reserves:
Injuries and damages
reserve $1,500 $1,804 $ - $1,804 $1,500
Miscellaneous
operating reserves $ 748 $ 429 $ (156) $ 81 $ 940
1993:
Reserves Deducted From
Applicable Assets:
Reserve for
uncollectible
accounts $1,421 $1,174 $1,001(2) $2,219 $1,377
Other Reserves:
Injuries and damages
reserve $1,500 $2,820 $ - $2,820 $1,500
Miscellaneous
operating reserves $ - $ 870 $ 332 $ 454 $ 748
NOTES: (1) Represents deductions from the reserves for purposes for
which the reserves were created.
(2) Represents collections of accounts previously written off.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be
signed on its behalf by the undersigned, thereunto duly authorized.
IDAHO POWER COMPANY
(Registrant)
March 14, 1996 By: /s/Joseph W. Marshall
Joseph W. Marshall
Chairman of the Board and
Chief Executive Officer and Director
Pursuant to the requirements of the Securities Exchange Act of 1934,
this report is signed below by the following persons on behalf of the
Registrant and in the capacities and on the dates indicated.
By: /s/Joseph W. Marshall Chairman of the Board and March 14, 1996
Joseph W. Marshall Chief Executive Officer and Director
By: /s/Larry R. Gunnoe President and Chief Operating "
Larry R. Gunnoe Officer and Director
By: /s/J. LaMont Keen Vice President and Chief Financial "
J. LaMont Keen Officer (Principal Financial Officer)
By: /s/Harold J. Hochhalter Controller and Chief Accounting Officer "
Harold J. Hochhalter (Principal Accounting Officer)
By: /s/Robert D. Bolinder By: /s/Evelyn Loveless "
Robert D. Bolinder Evelyn Loveless
Director Director
By: /s/Roger L. Breezley By: /s/Jon H. Miller "
Roger L. Breezley Jon H. Miller
Director Director
By: /s/John B. Carley By: /s/Peter S. O'Neill "
John B. Carley Peter S. O'Neill
Director Director
By: /s/Peter T. Johnson By: /s/Gene C. Rose "
Peter T. Johnson Gene C. Rose
Director Director
By: /s/ Jack K. Lemley By: /s/Phil Soulen "
Jack K. Lemley Phil Soulen
Director Director
EXHIBIT INDEX
Exhibit Page
Number Number
12 Statement Re: Computation of Ratio of Earnings 70
to Fixed Charges
12(a) Statement Re: Computation of Supplemental 71
Ratio of Earnings to Fixed Charges.
12(b) Statement Re: Computation of Ratio of Earnings 72
to Combined Fixed Charges and Preferred
Dividend Requirements.
12(c) Statement Re: Computation of Supplemental 73
Ratio of Earnings to Combined Fixed Charges
and Preferred Dividend Requirements.
23 Independent Auditor's Consent. 74
27 Financial Data Schedule 75