Back to GetFilings.com
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.