112
TABLE OF CONTENTS
PART I
PAGE
ITEM 1. BUSINESS 2
GENERAL 2
POWER SUPPLY 5
DIVERSIFIED BUSINESS OPERATIONS 6
ELECTRIC INDUSTRY RESTRUCTURING 7
FUEL 7
WATER RIGHTS 8
REGULATION 9
ENVIRONMENTAL REGULATION 9
RATES 11
CONSTRUCTION PROGRAM 12
FINANCING PROGRAM 13
ITEM 2. PROPERTIES 14
ITEM 3. LEGAL PROCEEDINGS 16
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS 18
EXECUTIVE OFFICERS OF THE REGISTRANTS 18
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON STOCK AND RELATED
STOCKHOLDER MATTERS 20
ITEM 6. SELECTED FINANCIAL DATA 21
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS 22
ITEM 7A.QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT
MARKET RISK 36
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA 37
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE 72
PART III
ITEM 10.DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANTS*
72
ITEM 11.EXECUTIVE COMPENSATION* 72
ITEM 12.SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT* 72
ITEM 13.CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS* 72
PART IV
ITEM 14.EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS
ON FORM 8-K 72
SIGNATURES 78-79
*INCORPORATED BY REFERENCE.
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K-405
(Mark One)
X ANNUAL REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 1998
OR
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from ................... to
.................................................................
Exact name of Registrants as specified in
Commissiontheir charters, address of principal executive IRS
Employer Iden-
File Numberoffices and Registrants' telephone number tification
Number
1-14465 IDACORP, Inc. 82-0505802
1-3198 Idaho Power Company 82-0130980
1221 W. Idaho Street
Boise, ID 83702-5627
(208) 388-2200
State or other jurisdiction of incorporation: Idaho
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT: Name of
exchange on
which registered
IDACORP, Inc.: Common Stock, without par value
New York and Pacific
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:
Idaho Power Company: Preferred Stock
Indicate by check mark whether the registrants (1) have filed all
reports required to be filed by Section 13 or 15(d) of the
Securities Exchange Act of 1934 during the preceding 12 months (or
for such shorter period that the registrants were required to file
such reports), and (2) have been subject to such filing
requirements for the past 90 days.
Yes ( X ) No ( )
Indicate by check mark if disclosure of delinquent filers pursuant
to Item 405 of Regulation S-K is not contained herein, and will not
be contained, to the best of registrants' knowledge, in definitive
proxy or information statements incorporated by reference in Part
III of this Form 10-K or any amendment to this Form 10-K. ( X )
Aggregate market value of voting and non-voting common stock held
by nonaffiliates (March 1, 1999)
IDACORP, Inc.: 37,497,405
Idaho Power Company: None
Number of shares of common stock outstanding at February 28, 1999:
IDACORP, Inc.: 37,612,351
Idaho Power Company: 37,612,351 shares all of which are held by
IDACORP, Inc.
Documents Incorporated by Reference:
Part III, Item 10 Portions of the joint proxy statement of the
Registrants.
Item 11 to be filed pursuant to Regulation 14A for the 1999
Annual Meeting of Shareholders to be Item 12 held on May
5, 1999.
Item 13
PART I - IDACORP, Inc. and Idaho Power Company:
ITEM 1. BUSINESS
SAFE HARBOR STATEMENT
This Form 10-K contains "forward-looking statements" intended to
qualify for safe harbor from liability established by the Private
Securities Litigation Reform Act of 1995. Forward-looking
statements should be read with the cautionary statements and
important factors included in this Form 10-K at Part II, Item 7-
Management's Discussion and Analysis of Financial Condition and
Results of Operations - Forward-Looking Information. Forward-
looking statements are all statements other than statements of
historical fact, including without limitation those that are
identified by the use of the words "anticipates," "estimates,"
"expects," "intends," "plans," "predicts," and similar expressions.
GENERAL
IDACORP, Inc. (Company), a holding company, was incorporated under
the laws of the state of Idaho in 1998. The Company's principal
subsidiary is Idaho Power Company (IPC), an electric public utility
company that represents over 90 percent of the Company's total
assets and is its principal operating subsidiary. The Company's
other subsidiaries are Ida-West Energy Company (Ida-West) and
IDACORP Energy Solutions Inc. (IES).
Subsidiaries of IDACORP -
IPC 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. IPC 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
780,000. IPC holds franchises in approximately 70 cities in Idaho
and ten cities in Oregon, and holds certificates from the
respective public utility regulatory authorities to serve all or a
portion of 28 counties in Idaho, three counties in Oregon and one
county in Nevada. As of December 31, 1998, IPC supplied electric
energy to 373,730 general business customers and employed 1,669
people in its operations.
IPC's results of operations, like those of certain other utilities
in the Northwest, can be significantly affected by changing
weather, precipitation and streamflow conditions. In 1993 a power
cost adjustment (PCA) mechanism was implemented in IPC's Idaho
jurisdiction. With the implementation of the PCA, which includes a
major portion of the operating expenses with the largest variation
potential (net power supply costs), IPC's operating results are
more dependent upon general regulatory, economic, temperature and
competitive conditions and less on 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.
IPC operates 17 hydro power plants and shares ownership in three
coal-fired generating plants (see Item 2 - "Properties"). IPC
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. IPC has participated in the development
of thermal generation in Wyoming, Oregon and Nevada using low-
sulfur coal from Wyoming and Utah.
For the year ended December 31, 1998, total revenues from
residential customers accounted for 41percent of total general
business revenues. Commercial customers with less than 1,000
kilowatt (kW) demand accounted for 23 percent, industrial customers
with 1,000 kW demand and over accounted for 24 percent, irrigation
customers accounted for 11 percent and other revenues accounted for
1 percent.
IPC's principal commercial and industrial customers are involved
in: elemental phosphorus production; food processing; phosphate
fertilizer production; electronics and general manufacturing;
lumber; beet sugar refining; and the recreation industry, such as
lodges, condominiums, ski lifts and related facilities.
The off-system revenue percentage increased in 1998 due primarily
to increases in electricity trading activity. Firm energy demand,
hydroelectric generating conditions and market conditions
throughout the west also affect the volume and price of off-system
sales.
IPC intends to be a competitive energy provider, including both
electricity and natural gas and operates gas trading offices in
Houston, Texas to serve the southern and eastern United States and
Boise, Idaho, to serve the northwest and Canadian markets. IPC has
also significantly increased its participation in the wholesale
electricity markets.
Ida-West was formed in 1989 to participate through partnership
interests in cogeneration and small power production (CSPP)
projects. Ida-West holds investments in 13 operating hydroelectric
plants with a total generating capacity of approximately 72
megawatts (MW).
In November 1996, Ida-West purchased an interest in five
hydroelectric projects located in Shasta County, California, with a
total generating capacity of 11.2 MW. Ida-West acquired the
projects through a limited liability company in which it holds a 50
percent interest.
Ida-West has a partnership interest in the Hermiston Power Project,
a 536 MW, gas-fired project to be located near Hermiston, Oregon.
Ida-West has been responsible for managing all permitting and
development activities relating to the project since its inception
in 1993, and has obtained all permits necessary for construction
and operation of the project. The partnership is exploring various
alternatives for marketing the project's output. Construction of
this project could begin in 1999.
IPC has purchased all of the power from the five Idaho
hydroelectric entities that are fifty percent owned by Ida-West,
totaling approximately $8.7 million in 1998. At December 31, 1998,
total investment in Ida-West was $26.9 million.
IES was created in December 1997 to address and pursue
opportunities to provide expanded products and services to present
and future customers. To date there has been limited activity in
this entity.
Subsidiaries of IPC -
Idaho Energy Resources Company (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 power plant near Rock Springs, Wyoming (see
"Fuel"). As of December 31, 1998, total investment in IERCo was
$10.7 million.
IDACORP Financial Services, Inc. (IFS), was organized in 1986 to
pursue a non-regulated diversification program. At the end of 1998
IFS was participating in 12 affordable housing programs which
provide a return primarily by reducing federal income taxes through
tax credits and tax depreciation benefits. As of December 31,
1998, total investment in IFS was $15.0 million.
Stellar Dynamics, Inc (Stellar) was formed in 1995 to commercialize
expertise in control technology for electric substations and power
plants. Currently, Stellar's market focus is in complex control
and automation systems for the electric utility sector and
industrial applications. Stellar also provides design and
engineering for complete electric substations. Stellar markets its
products nationally and internationally. As of December 31, 1998,
total investment in Stellar was $1.1 million.
Applied Power Corporation (APC) is a Lacey, Washington based
company that designs, supplies and distributes photovoltaic (PV)
systems. APC provides reliable, cost-effective solar electric
products and systems for industry, contractors, utilities,
government and an international network of solar dealers and
distributors. As of December 31, 1998, total investment in APC was
$4.7 million.
Pathnet/Idaho Equipment, LLC (Pathnet) was formed in 1998 to
develop and distribute microwave communication services and
products. As of December 31, 1998, total investment in Pathnet was
$1.5 million.
Research and Development, Renewable Energy Sources and Fuel
Cells -
During 1998, the Company spent approximately $1.2 million on
research and development of which $0.9 million was through
membership in Electric Power Research Institute (EPRI). EPRI's
mission is to discover, develop and deliver advances in science and
technology. Some of the subjects of EPRI projects include:
electrification technologies, power quality, electric
transportation systems, EMF assessment/risk management and air
quality issues. IPC 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 IPC.
In 1992, IPC joined Southern California Edison, the U.S. Department
of Energy (DOE) and others in retrofitting an existing 10-megawatt
central receiver solar thermal experimental power plant now called
Solar Two near Barstow, California. IPC has contributed $630,500
through 1998 and EPRI contributed an additional $630,500 of
matching funds, bringing credited contribution to approximately
$1.3 million. Solar Two was first synchronized to Southern
California Edison's system in May 1996.
In 1998, IPC entered into an agreement with Proton Energy Systems
(PES) to purchase an electrolyzer that produces hydrogen from
electricity. IPC is conducting a pilot program with the
electrolyzer as part of its efforts to gain experience with fuel
cells and to gain first-hand working knowledge and information
about the technology. Because of IPC's low cost of electrical
power, there is great potential that the electrolyzer can supply
high-value hydrogen to consumers at their plant sites and at a
lower cost than conventional bottled hydrogen. IPC has an
agreement with the DOE, Lockheed and PES to test the electrolyzer
and validate the operating characteristics of the unit.
In May 1998, a subsidiary of IPC entered into a Research and
Development and Option Agreement with Northwest Power
Systems (NPS) to provide technical and financial resources to NPS
for the on-going development of a fully integrated, small-scale
fuel cell. NPS has patented a unique fuel reformer that allows for
the processing of a number of fuels into hydrogen that is then used
for the generation of electricity. A fully operational prototype
has been constructed and successfully tested.
Energy Efficiency -
As an active member of the Northwest Energy Efficiency Alliance,
IPC has been shifting the focus of its conservation, or demand-side
management (DSM), activities towards regional market transformation
efforts and renewing its commitment to public purpose programs. At
the same time, IPC has discontinued many of the traditional DSM
programs that required deferral of costs. In 1998, $2.9 million
was expended on energy-efficiency programs.
POWER SUPPLY
IPC meets its system load requirements using a combination of its
own system generation, mandated purchases from private developers
(see CSPP purchases below) and purchases from other utilities and
power producers. IPC's generating stations and capacities are
listed in Item 2. Properties. Historically, under normal water
conditions, IPC's hydro system supplies approximately 56 percent,
thermal generation accounts for 33 percent and purchased power and
other interchanges contribute the remaining 11 percent of total
system requirements.
IPC's system is dual-peaking, with the larger peak demand generally
occurring in the summer. The system peak demand for 1998 was 2,747
MW, set on July 14, 1998. Peak demands in 1997 and 1996 were 2,545
MW and 2,661 MW respectively. IPC periodically updates its load
and resource projections and now expects total system energy
requirements to grow 2.0 percent annually over the next five years.
Because of its reliance upon hydroelectric generation, which varies
according to streamflows, IPC's generating system is constrained
more by resource availability than by capacity. 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 contract
that expires in 2000 and with Seattle City Light under a contract
that expires in 2003.
During the 1999-2003 period, IPC plans to provide all the energy
required to serve its firm load requirements by using its
hydroelectric and coal-fired generating units, supplemented by
purchases of power from neighboring utilities or marketing
entities.
Even though its significant hydroelectric generation can operate to
meet peak demands, seasonal energy requirements are important to
IPC because its seasonal energy capability is determined in part by
the availability of water. In 1996, 1997 and 1998, IPC's hydro
generating system experienced above average water years. Early
reports for 1999 indicate that three major factors affecting hydro
production, mountain snowpack, carryover reservoir storage and
precipitation are all above normal for the time of year.
IPC'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.
IPC's transmission system is directly interconnected with the
transmission systems of the Bonneville Power Administration (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 interchange, purchase and sale of power among most of
the electric systems in the West. IPC is a member of 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.
CSPP Purchases -
As a result of the enactment of the Public Utilities Regulatory
Policy Act of 1978 (PURPA) and the adoption of avoided cost
standards by the IPUC, IPC has entered into contracts for the
purchase of energy from private developers. Because IPC's service
territory encompasses substantial irrigation canal development,
forest product production facilities, mountain streams, and food
processing facilities, considerable amounts of energy are available
from these sources. Such energy comes from hydropower 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 66 CSPP projects on-line as
of December 31, 1998 is $58.0 million. During 1998, IPC purchased
907.1 million kWh of power from these private developers at a
blended price of 6.0 cents per kWh.
In 1995 IPC received approval from the IPUC to reduce published
CSPP rates for new projects less than one MW. In addition, the
IPUC determined that negotiated rates for future CSPP projects
larger than one MW should be tied more closely to values determined
in IPC's integrated resource planning process. In subsequent
orders, the IPUC limited the length of new contracts to a maximum
of five years (see "Rates").
Wholesale Power Sales -
IPC has firm wholesale power sales contracts with several entities.
These contracts are for various amounts of energy, ranging up to 100
average MW, and are of various lengths expiring between 1999 and
2009. IPC is actively participating in the wholesale electricity
markets and as a result, has increased significantly the volume of
electricity sold and purchased. IPC is actively marketing this power
to other entities as it becomes available.
Transmission Services -
IPC has long had an informal open-access transmission policy and is
experienced in providing reliable, high quality, economical
transmission service. IPC provides various firm and non-firm
wheeling services for several surrounding utilities.
In 1996 the FERC issued Order Nos. 888 and 889 dealing with open
access non-discriminatory transmission services by public
utilities, and standards of conduct regarding these services.
These orders require public utilities owning transmission lines to
file open-access tariffs available to buyers and sellers of
wholesale electricity; to require utilities to use the tariffs for
their own wholesale sales; and to allow utilities to recover
stranded costs, subject to certain conditions. Public utilities
owning transmission lines were required to file compliance tariffs
by July 9, 1996.
In November 1995, IPC filed open-access tariffs with the FERC for
Point-to Point and Network transmission service. The substance of
these tariffs was to offer the same quality and character of
transmission services that IPC uses in its own operations to anyone
seeking them. IPC requested and received permission to implement
these tariffs beginning February 1, 1996. On July 8, 1996, IPC
filed a new open-access transmission tariff to replace the 1995
tariffs. This provides full compliance with Final Order No. 888.
This new filing did not include a rate change. On November 13,
1996, the FERC issued an unconditional acceptance of the terms and
conditions of this tariff. The rate was not subject to review.
IPC'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 allows IPC to provide
transmission services and reach a broad power sales market.
DIVERSIFIED BUSINESS OPERATIONS
The Company has been pursuing a strategy of expanding non-regulated
activities and separating regulated from non-regulated activities.
The following discussion relates to these expanded activities.
In 1997 and 1998 IPC greatly increased its participation in the
western wholesale electricity markets. In mid-1997, IPC began
trading natural gas. By December 1998, natural gas sales volumes
exceeded 482 million cubic feet per day. These changes reflect the
Company's intent to be a competitive energy provider of both of
these commodities.
In 1998, the Company began offering two new products to retail
customers, satellite television and billpayer insurance.
On February 17, 1998, the Company announced it had joined the
Allied Utility Network (AUN), a member-supported alliance that
provides customer research, marketing and other support services to
utilities. Through its relationship with AUN, the Company is
developing new products and services to offer to retail customers.
Other members of the alliance include Colorado Springs Utilities of
Colorado Springs, Colorado, Omaha Public Power District of Omaha,
Nebraska, Snapping Shoals EMC of Covington, Georgia and Cobb
Electric Membership Corporation of Marietta, Georgia.
Collectively, the utilities serve approximately one million
customers.
By the end of 1999, the Company intends to have transferred IPC's
non-utility business activities and unregulated subsidiaries under
the holding company or its unregulated subsidiaries.
ELECTRIC INDUSTRY RESTRUCTURING
Competition is increasing in the electric utility industry. The
legislatures and/or the regulatory commissions in several states,
and at a national level, 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 traditional service territory. A requirement to transmit
directly to retail customers would permit retail customers to
purchase electric capacity and energy from their local electric
utility or from any other electric utility or independent power
supplier.
In 1997, the Idaho Legislature appointed a committee to study
restructuring of the electric utility industry. Legislation
resulting from this committee required the IPUC to begin an
investigation into the unbundling of costs into its various
delivery and energy components. IPC filed cost unbundling studies
in July and December 1997. The IPUC compiled cost data presented
by all the electric utilities and presented that information to the
legislature. Although the committee will continue studying a
variety of restructuring ideas, it is not expected to recommend
restructuring legislation in the foreseeable future.
In response to the changing electric utility industry, IPC has
adjusted its resource acquisition policy to emphasize resource
marketability. IPC 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 IPC's
requirements. In practice, this policy will result in the purchase
of power from others through the marketplace when purchases are the
lowest cost resources, and new investment in resource ownership by
IPC only when a Company-owned resource would be cost effective.
With a predominantly hydroelectric base and low-cost thermal
plants, IPC is one of the lowest cost producers of electric energy
among the nation's investor-owned utilities. Through its
interconnections with BPA and other utilities, IPC has access to
all the major electric systems in the West.
FUEL
IPC, through Idaho Energy Resources Co., owns a one-third interest
in the Bridger Coal Company, which owns the Jim Bridger coal mine
supplying coal to the Jim Bridger generating plant in Wyoming. The
mine, located near the Jim Bridger plant, operates under a long-
term sales agreement that provides for delivery of coal over a 51-
year period ending in 2025 (See Item 2 "Properties"). The Jim
Bridger coal mine has sufficient reserves to provide coal
deliveries pursuant to the sales agreement. IPC 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.
Portland General Electric (PGE), with whom IPC is a ten-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
IPC to take advantage of lower-cost spot market coal for some or
all of the Boardman plant's requirements.
SPPCo, with whom IPC 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 1981 with Southern Utah Fuel Company, a subsidiary of Canyon
Fuel Co., LLC, 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 300,000 tons per year to a maximum of
1,000,000 tons per year. This flexibility accommodates
fluctuations in energy demand, hydroelectric generating conditions
and purchases of energy from CSPP facilities.
WATER RIGHTS
Except as discussed below, IPC has acquired valid water rights
under applicable state law for all waters used in its hydroelectric
generating facilities. In addition, IPC holds water rights for
domestic, irrigation, commercial and other necessary purposes
related to other land and facility holdings within the state. The
exercise and use of all of these water rights are subject to prior
rights and, with respect to certain hydroelectric facilities, IPC's
water rights for power generation are subordinated to future
upstream diversions of water for irrigation and other recognized
consumptive uses.
Over time, increased irrigation development and other consumptive
diversions have resulted in some reduction in the stream flows
available to fulfill the IPC's water rights at certain
hydroelectric generating facilities. In reaction to these
reductions, IPC initiated and continues to pursue a course of
action to determine and protect its water rights. As part of this
process, IPC and the state of Idaho signed the Swan Falls agreement
on October 25, 1984, which provided a level of protection for IPC's
hydropower water rights at specified plants by setting minimum
stream flows and establishing an administrative process governing
the future development of water rights that may affect IPC's
hydroelectric generation. In 1987, Congress passed and the
President signed into law House Bill 519. This legislation
permitted implementation of the Swan Falls agreement and further
provided that during the remaining term of certain of IPC's project
licenses that the relationship established by the agreement would
not be considered by the FERC as being inconsistent with the terms
of IPC's project licenses or imprudent for the purposes of
determining rates under Section 205 of the Federal Power Act. The
FERC entered an order implementing the legislation on March 25,
1988.
In addition to providing for the protection of IPC's hydropower
water rights, the Swan Falls agreement contemplated the initiation
of a general adjudication of all water uses within the Snake River
basin. In 1987, the director of the Idaho Department of Water
Resources filed a petition in state district court asking that the
court adjudicate all claims to water rights, whether based on state
or federal law, within the Snake River basin. A commencement order
initiating the Snake River Basin Adjudication was signed by the
court on November 19, 1987. This legal proceeding was authorized
by state statute based upon a determination by the Idaho
Legislature that the effective management of the waters of the
Snake River basin required a comprehensive determination of the
nature, extent and priority of all water uses within the basin.
The adjudication is expected to continue past the turn of the
century. IPC has filed claims to its water rights within the basin
and is actively participating in the adjudication to ensure that
its water rights and the operation of its hydroelectric facilities
are not adversely impacted. IPC does not anticipate any
modification of its water rights as a result of the adjudication
process.
REGULATION
IPC 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 Utility Commission (OPUC) and the
Public Service Commission of Nevada. IPC is also under the
regulatory jurisdiction of the IPUC, OPUC and the Public Service
Commission of Wyoming as to the issuance of securities. IPC is
subject to the provisions of the Federal Power Act as a "licensee"
and "public utility" as therein defined. IPC'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 IPC's purchase of power from CSPP facilities.
As a licensee under the Federal Power Act, IPC 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 related FERC regulations. These conditions and regulations
include 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. IPC'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. With respect to project property located in Oregon, these
facilities are subject to the Oregon Hydroelectric Act. IPC has
obtained Oregon licenses for these facilities and these licenses
are not in conflict with the Federal Power Act or IPC'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 IPC'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 present environmental laws and regulations, IPC
estimates its capital expenditures (excluding allowance for funds
used during construction) for environmental matters for 1999 and
during the period 2000-2003 will total approximately $9.5 million
and $48.0 million, respectively. Mitigation of environmental
concerns due to relicensing of hydro facilities will be a major
portion of these expenditures. IPC anticipates incurring
approximately $23.8 million annually of operating expenses for
environmental facilities during the period 1999-2003, based upon
present environmental laws and regulation.
Clean Air -
IPC has analyzed the Clean Air Act's legislation and its effects
upon IPC and its ratepayers. IPC's coal-fired plants in Nevada and
Oregon already meet the federal emission rate standards for sulfur
dioxide (SO2) and IPC's coal-fired plant in Wyoming meets that
state's even more stringent SO2 regulations. The Company foresees
no adverse effects upon its operations with regard to SO2
emissions.
On July 16, 1997, the EPA announced new National Ambient Air Quality
Standards for ozone and Particulate Matter (PM). In addition to
these standards, on July 17, 1997, the EPA proposed regional haze
regulations for protection of visibility in national parks and
wilderness areas. Impacts of the ozone and PM regulations and the
proposed regional haze regulations on IPC's thermal operations are
unkown at this time.
Although not presently required to meet any federal nitrogen oxide
(NOx) limits, North Valmy, Boardman, and Jim Bridger Unit 4 elected
to meet Phase I NOx limits beginning in 1998. As a result of this
voluntary "early election" these units will not be required to meet
the more restrictive Phase II NOx limits until 2008. Had the units
not voluntarily "early elected," they would have been required to
meet the Phase II NOx beginning in 2000. Jim Bridger Units 1, 2
and 3 were accepted as substitution units in 1995 and subject to
NOx limits of Phase I instead of the more restrictive limits of
Phase II. Jim Bridger is in the process of installing low NOx
burners to reduce NOx levels even lower than currently required.
Water -
IPC 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.
IPC has agreed to meet certain dissolved oxygen standards at its
American Falls hydroelectric generating plant. IPC signed
amendments to the agreements relating to the operation of the
American Falls Dam and the location of water quality monitoring
facilities. The amendments were made to provide more accurate and
reliable water quality measurements necessary to maintain water
quality standards downstream from IPC's plant during the May 15 to
October 15 period each year.
IPC has 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. IPC has also installed and
operates water quality monitors at the Milner and Twin Falls
hydroelectric projects, in order to meet compliance standards for
water quality.
IPC 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,
IPC sponsors ongoing programs for the control of fish disease and
improvement of fish production. IPC'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. At December 31, 1998, the investment in these
facilities was $12.2 million and the annual cost of operation
pursuant to FERC License 1971 was $2.4 million for 1998.
Endangered Species -
Several species of salmon and Snake River mollusks living within
IPC's operating area are listed as threatened or endangered. IPC
continues to review and analyze the effect such designation has on
its operations. IPC is cooperating with various governmental
agencies to resolve issues related to these species. (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. IPC
continues to meet all federal requirements of TSCA for the
continued use of equipment containing PCBs. IPC has a program to
make the 200-plus substations on its system non-PCB. While IPC's
use of equipment containing PCBs falls well within the federal
standards, IPC has voluntarily decided to virtually eliminate these
compounds from its 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 IPC costs for the disposal of
PCBs from the Company's system were $0.9 million, $1.0 million and
$0.5 million for 1996, 1997 and 1998 respectively. All generation
facilities are presently non-PCB. IPC anticipates that all of its
substations, except for capacitors, will be non-PCB by the end of
1999.
RATES
Idaho Jurisdiction
The May 1998 adjustment to rates includes the deferred costs from
the 1997-98 PCA year as well as the difference between base power
supply cost assumptions and forecasted power supply costs. The
1998-99 forecast assumed a return to more normal hydroelectric
generating conditions. This resulted in forecasted net power
supply costs being near the amounts used to establish base rates in
past regulatory proceedings. The May 1998 rate adjustment
increases expected annual revenue by $34.0 million above the amount
that would have been received at the 1997 rates, and $17.3 million
above what would be expected at base rates during this rate period.
So far in the current rate period, actual power costs have been
less than forecast, due to better than forecast hydroelectric
generating conditions. We have recorded a reduction to regulatory
assets of $10.4 million as of December 31, 1998. The variance that
exists at the end of the 1998-99 rate period will be trued-up in
the next annual PCA adjustment.
The May 1996 PCA adjustment decreased Idaho jurisdictional PCA
rates 5.9%. IPC's May 1997 PCA adjustment, combined with the
revenue sharing mechanism described below, decreased rates an
additional 0.63%.
On August 3, 1995, IPC filed a proposal with the IPUC to support
IPC's organizational redesign. In response to IPC's proposal, the
IPUC approved a Settlement that authorizes IPC to defer and
amortize costs related to reorganization in return for a general
rate freeze through the end of 1999. The Settlement gives IPC time
to pursue and to implement its efficiency and growth initiatives
with the assurance of a reasonable level of financial performance
without the need to change customer prices.
Under the Settlement, which remains in effect through 1999, when
IPC's actual annual earnings exceed an 11.75 percent return on year-
end common equity for the Idaho jurisdiction, IPC will share 50
percent of the additional earnings with its Idaho retail customers.
IPC set aside approximately $4.9 million and $7.6 million in 1996
and 1997 respectively for the benefit of its Idaho customers. Of
the $4.9 million set aside in 1996, $1.4 million was applied
against the regulatory asset balance of Idaho demand-side
management/conservation (DSM) expenditures while the remaining $3.5
million was refunded. Of the $7.6 million set aside in 1997, $3.0
million was applied against the DSM regulatory asset balance, $2.7
million was used to fund (through May 15, 1999) a DSM-related rate
increase, $0.8 million to recover 1997 Northwest Energy Efficiency
Alliance (NEEA) expenditures, and the remainder was held in reserve
to fund 1998 NEEA expenses once they have been approved for
recovery by the IPUC. IPC has set aside approximately $5.4 million
in 1998 for the benefit of its Idaho customers. The ultimate
disposition of this benefit is yet to be determined.
In addition, the Settlement allows for the accelerated amortization
of regulatory liabilities associated with accumulated deferred
investment tax credits (ADITCs) to provide a minimum 11.50 percent
return on actual year-end common equity for the Idaho jurisdiction.
IPC has received approval from the Idaho State Tax Commission and
the Internal Revenue Service on the accounting treatment for the
tax credits up to a maximum of $30 million of ADITC's. As of
December 31, 1998, no ADITCs have been used under the regulatory
agreement.
Other important points in the Settlement are that IPC will not be
allowed to increase its Idaho general rates prior to January 1,
2000, except under special conditions as defined in the Settlement,
and that the Company agrees that its quality of service will not
decline as a result of corporate reorganization.
In 1998, IPC received an order from the IPUC reducing the
amortization period for the regulatory assets associated with
demand-side management programs from 24 years to 12 years. At the
same time the IPUC approved an additional $16 million of Idaho
allocated demand-side management expenditures for recovery through
rates resulting in an increase of 0.67 percent to Idaho customers
effective May 16, 1999. At present this increase is being funded
through amounts set aside for 1997 customer revenue sharing. The
IPUC order has been appealed to the Idaho Supreme Court by a
customer group.
In December 1993, IPC filed with the IPUC for permission to approve
lower published prices for new CSPP contracts. In response to
IPC's filing, the IPUC issued an order on January 31, 1995,
approving lower published CSPP rates for new projects. In
addition, the IPUC determined that negotiated rates for future CSPP
projects larger than one MW should be tied more closely to values
determined by IPC's integrated resource planning process. In a
subsequent order issued on September 4, 1996, the IPUC limited the
contract term that a new CSPP project larger than one MW could
request to a maximum of five years.
Other Jurisdictions -
In 1998, IPC received authority from the OPUC to reduce the
amortization period for the regulatory assets associated with
demand-side management programs from 24 years to five years. The
OPUC also approved additional Oregon allocated demand-side
management expenditures for recovery through rates. The Oregon
costs will be recovered by extending an existing surcharge until
the amounts are collected.
In 1997, IPC did not file any applications for rate relief before
the FERC or in its Oregon or Nevada retail jurisdictions. In July
1996, IPC filed an open-access tariff with the FERC, in compliance
with Order 888. The terms and conditions of the tariff were
approved for use beginning in 1997 (see "Transmission Services").
CONSTRUCTION PROGRAM
The Company's construction program for the 1999-2003 period
(excluding allowances for funds used during construction) is
presently estimated to require cash funds of approximately $642.4
million as follows:
1999 2000-2003 (a)
(Millions of Dollars)
Generating Facilities:
Hydro $14.2 $65.2
Thermal 6.5 30.3
Total generating facilities 20.7 95.5
Transmission lines and
substations 18.1 62.5
Distribution lines and
substations 43.4 198.3
General 28.4 53.7
Total cash construction - IPC 110.6 410.0
Other 4.9 116.9
Total IDACORP $115.5 $526.9
(a) Escalation rates were not applied to construction
expenditures because the level of expenditures has
been capped.
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 including: (1)
efficiency improvements on the Company's generation, transmission
and distribution systems and (2) purchased power and exchange
agreements with other utilities or other power suppliers. The
Company will pursue the projects that best meet its future energy
needs.
FINANCING PROGRAM
The five-year estimates of capital requirements and sources of
capital are outlined in the following tables:
IDACORP, Inc. Idaho Power Company
1999 2000-2003 1999 2000-2003
(Millions of Dollars)
Capital Requirements:
Net cash construction
expenditures $115.5 $526.9 $110.6 $410.0
Conservation expenditures 1.9 0.0 1.9 0.0
Other cash expenditures 3.8 4.8 3.8 4.8
Total $121.2 $531.7 $116.3 $414.8
Sources of Capital:
Internal generation $ 94.4 $518.7 $ 94.2 $468.5
Short-term bank loans - Net 23.4 3.8 19.2 5.0
First mortgage bonds (0.1) 9.5 0.0 (58.4)
Debt repayment (0.1) (0.3) (0.1) (0.3)
Common stock 0.0 0.0 0.0 0.0
Cash investments (increase) 3.5 0.0 3.0 0.0
Total $121.2 $531.7 $116.3 $414.8
These estimates are subject to constant revision in light of
changing economic, regulatory and environmental factors and
patterns of conservation. Any additional securities to be sold
will depend upon market conditions and other factors. The Company
will continue to take advantage of any refinancing opportunities as
they become available.
Under the terms of the Indenture relating to IPC'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, 1998, net earnings were 6.40 times. Additional
preferred stock may be issued when earnings for twelve consecutive
months within the preceding fifteen months are at least equal to
l.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, 1998, the actual preferred
dividend earnings coverage was 3.15 times. If the dividends on the
shares of Auction Preferred Stock were to reach the maximum
allowed, the preferred dividend earnings coverage would be 2.88
times. The Indenture and IPC'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
IPC'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 4,644 miles of high voltage
transmission lines; 21 step-up transmission substations located at
power plants; 17 transmission substations; 7 transmission switching
stations; and 205 energized distribution substations (excludes
mobile substations and dispatch centers).
IPC 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
Project Operating Nameplate License
Capacity kW Capacity kW Expiration
Properties Subject to
Federal Licenses:
Lower Salmon 70,000 60,000 1997 (a)
Bliss 80,000 75,000 1998 (a)
Upper Salmon 39,000 34,500 1998 (a)
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
Milner 59,448 59,448 2038
Twin Falls 54,300 52,737 2041
Other Generating Plants:
Other Hydroelectric 10,400 11,300
Jim Bridger (coal-
fired station) 708,333 709,617
Valmy (coal-fired
station) 260,650 260,650
Boardman (coal-fired
station) 53,000 56,050
(a)Renewed on a year-to-year basis; application for relicense
pending.
At December 31, 1998, the composite average ages of the principal
parts of IPC's system, based on dollar investment, were: production
plant, 18.8 years; transmission system and substations, 19.0 years;
and distribution lines and substations, 15.1 years. IPC considers
its properties to be well maintained and in good operating
condition.
IPC 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. IPC's property is also subject to the lien of its
Mortgage and Deed of Trust and the provisions of its project
licenses. In addition, IPC's property is subject to minor defects
common to properties of such size and character that do not
materially impair the value to, or the use by, IPC 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 IPC is the
relicensing of its hydro facilities. The relicensing of these
projects is not automatic under federal law. IPC 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 IPC continuing to hold
the federal licenses. IPC is actively pursuing the relicensing of
its hydroelectric projects, a process that will continue for the
next 10 to 15 years. IPC submitted its first applications for
license renewal to the FERC in December 1995, seeking renewal of
IPC's licenses for its Bliss, Upper Salmon Falls and Lower Salmon
Falls hydroelectric projects. In May 1997 IPC submitted its
application for its Shoshone Falls project. IPC also submitted an
application for license renewal for its C J Strike hydroelectric
project on November 24, 1998. Although various federal
requirements and issues must be resolved through the license
renewal process, IPC anticipates that its efforts will be
successful. At this point, however, IPC cannot predict what type
of environmental or operational requirements it may face, nor can
it estimate the eventual cost of licensing renewal.
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 holds investments in thirteen operating hydroelectric
plants with a total generating capacity of 72 MW.
ITEM 3. LEGAL PROCEEDINGS
On November 30, 1995, a complaint entitled Idaho Power Company vs.
Cogeneration, Inc., Case No. 98467, was filed by IPC in the
District Court of the Fourth Judicial District of the State of
Idaho. The proceeding involves an effort by IPC 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, IPC 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, IPC 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 IPUC
order and has never posted the $1.9 million amount required by the
FESA.
After the IPUC's order became final and non-appealable, IPC filed a
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. IPC asked the district court to find that as
a matter of law IPC was entitled to either terminate or rescind the
FESA.
In response to IPC's complaint, Cogeneration, Inc. filed
counterclaims alleging that IPC, 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
IPC was entitled to either rescind or terminate the FESA.
On February 16, 1996, Cogeneration, Inc. dismissed its anti-trust
claims against IPC with prejudice, and on February 23, 1996, the
Idaho Supreme Court granted Cogeneration, Inc.'s request for an
expedited appeal of the District Court's decision establishing an
accelerated briefing schedule and scheduling oral argument for May
10, 1996.
On August 12, 1996, the Idaho Supreme Court determined that the
District Court's decision that Cogeneration, Inc. had breached the
FESA was premature.
On February 10, 1997, Cogeneration, Inc. filed an amended Complaint
restating its previous claims, requesting a jury trial rather than
the court trial it had previously requested and raising several new
allegations and claims.
Following a court trial, on June 24, 1998 the District Court issued
a memorandum decision finding that Cogeneration, Inc. had
materially breached the FESA and as a result IPC had properly
terminated the FESA.
On July 27, 1998, Cogeneration, Inc. filed a Notice of Appeal with
the Idaho Supreme Court.
Cogeneration, Inc. filed its opening brief in the Idaho Supreme
Court on February 16, 1999. IPC's brief is due March 16, 1999. It
is likely that oral argument will be set during the court's fall
term.
This matter has been previously reported in IPC's Form 10-K dated
March 12, 1998, and other IPC reports filed with the Securities and
Exchange Commission.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None
EXECUTIVE OFFICERS OF THE REGISTRANTS
The names, ages and positions of all of the executive officers
of IDACORP, Inc. and Idaho Power 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.
IDACORP, Inc.
Name, Age and Position Business Experience During Past Five
(5) Years*
Joseph W. Marshall, 60 Appointed February 2, 1998.
Chairman of the Board and
Chief Executive Officer
Jan B. Packwood, 55 Appointed February 2, 1998.
President and Chief
Operating Officer
J. LaMont Keen, 46 Appointed February 2, 1998.
Vice President, Chief
Financial Officer
and Treasurer
Richard Riazzi, 44 Appointed January 14, 1999.
Vice President -
Marketing and Sales
Robert W. Stahman, 54 Appointed February 2, 1998.
Vice President, General
Counsel and Secretary
*IDACORP, Inc. executive officers serve in the same capacities at
Idaho Power Company. For these officers business experience, during
the past five years, please refer to the next table.
Idaho Power Company
Name, Age and Position Business Experience During Past Five
(5) Years
Joseph W. Marshall, 60 Appointed August 18, 1989.
Chairman of the Board and
Chief Executive Officer
Jan B. Packwood, 55 Appointed September 1, 1997. Mr.
President and Chief Packwood was Executive Vice President
Operating Officer from July 11, 1996, to September 1,
1997, and Vice President-Power Supply
prior to July 11, 1996.
J. LaMont Keen, 46 Appointed March 14, 1996. Mr. Keen
Vice President, Chief was Vice President and Chief
Financial Officer Financial Officer prior to March 14,
and Treasurer 1996.
Kip W. Runyan, 48 Appointed August 1, 1997. Mr. Runyan
Vice President - Delivery was CEO of Ida-West Energy Company
prior to August 1, 1997.
Richard Riazzi, 44 Appointed January 9, 1997. Mr.
Vice President - Riazzi was Vice President, Corporate
Marketing and Sales Marketing (1995-1996) and was Vice
President of the Energy Group (1991-
1995) for Equitable Resources, Inc.
James C. Miller, 44 Appointed July 10, 1997. Mr. Miller
Vice President - was General Manager - Generation
Generation prior to July 10, 1997.
Cliff N. Olson, 49 Appointed July 11, 1991.
Vice President -Corporate
Services
Robert W. Stahman, 54 Appointed July 13, 1989.
Vice President, General
Counsel and Secretary
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON STOCK AND RELATED
STOCKHOLDER MATTERS
IDACORP, Inc.'s common stock (without par value) is traded on the
New York and Pacific Stock Exchanges. At December 31, 1998, there
were 25,307 holders of record and the year-end stock price was $36
3/16 per share. The outstanding shares of Idaho Power Company
common stock ($2.50 par value) are held by IDACORP, Inc. and are
not traded.
The following table shows the reported high and low sales price and
dividends paid for the years 1998 and 1997 as reported by the Wall
Street Journal as composite tape transactions. IDACORP, Inc.
became the holding company of Idaho Power Company on October 1,
1998. Amounts reported for periods prior to October 1, 1998, were
for Idaho Power Company only.
1998 Quarters
Common Stock, without par value: 1st 2nd 3rd 4th
High $38 1/16 $37 7/8 $35 $36 1/4
Low 33 15/16 32 15/16 29 7/8 31 1/8
Dividends paid per share (cents) 46.5 46.5 46.5 46.5
______________________________
1997 Quarters
Common Stock, without par value: 1st 2nd 3rd 4th
High $31 7/8 $31 1/2 $32 13/16 $37 3/4
Low 29 3/4 28 1/2 31 30 5/16
Dividends paid per share (cents) 46.5 46.5 46.5 46.5
ITEM 6. SELECTED FINANCIAL DATA
SUMMARY OF OPERATIONS (Thousands of Dollars except for per share amounts)
IDACORP, Inc.
1998 1997 1996 1995 1994
For the Years Ended
December 31,
Operating revenues $1,121,976 $ 748,503 $ 578,445 $ 545,621 $ 543,658
Income from operations 191,221 184,749 187,171 175,991 149,665
Net income 89,176 87,098 83,155 78,930 67,532
Earnings per average
common share 2.37 2.32 2.21 2.10 1.80
outstanding (basic and
diluted)
Dividends declared per 1.86 1.86 1.86 1.86 1.86
share
At December 31,
Total long-term debt* $ 815,937 $ 746,142 $ 769,810 $ 672,618 $ 693,206
Total assets 2,451,620 2,451,816 2,328,738 2,241,753 2,191,816
*Excludes amount due within one year.
The above data should be read in conjunction with IDACORP's
consolidated financial statements and notes to consolidated
financial statements included in this Annual Report on Form 10-K.
SUMMARY OF OPERATIONS (Thousands of Dollars except for per share
amounts and customer data)
IDAHO POWER COMPANY
1998 1997 1996 1995 1994
For the Years Ended
December 31,
Operating revenues $1,121,976 $ 748,503 $ 578,445 $ 545,621 $ 543,658
Income from operations 191,221 184,749 187,171 175,991 149,665
Net income 95,919 92,274 90,618 86,921 74,930
At December 31,
Total long-term debt* $ 815,937 $ 746,142 $ 769,810 $ 672,618 $ 693,206
Total assets 2,421,790 2,451,816 2,328,738 2,241,753 2,191,816
Utility Customer Data:
General business
customers 373,730 363,085 352,487 340,708 330,308
Average Kwh per customer 36,368 37,080 37,627 35,740 37,616
Average rate per Kwh 3.85 3.63 3.71 3.85 3.75
*Excludes amount due within one year.
The above data should be read in conjunction with Idaho Power
Company's consolidated financial statements and notes to
consolidated financial statements included in this Annual Report on
Form 10-K.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
In Management's Discussion and Analysis we explain the general
financial condition and results of operations of IDACORP, Inc. and
its subsidiaries (IDACORP or the Company). IDACORP is a holding
company formed in 1998 as the parent of Idaho Power Company (IPC),
Ida-West Energy Company, and IDACORP Energy Solutions, Inc. IPC, an
electric utility, is IDACORP's principal operating subsidiary, and
accounts for over 90 percent of our assets, revenue and net income.
The financial condition and results of operations of IPC are
currently the principal factors affecting the financial conditions
and results of operations of IDACORP.
As you read Management's Discussion and Analysis, it may be helpful
to refer to our Consolidated Statements of Income which present our
results of operations for the years ended December 31, 1998, 1997
and 1996. In our discussion we explain the significant annual
changes between specific line items in the Consolidated Statements
of Income.
FORWARD-LOOKING INFORMATION
In connection with the safe harbor provisions of the Private
Securities Litigation Reform Act of 1995 (Reform Act), we are
hereby filing cautionary statements identifying important factors
that could cause our actual results to differ materially from those
projected in forward-looking statements (as such term is defined in
the Reform Act) made by or on behalf of the Company in this Annual
Report, quarterly report on Form 10-Q, in presentations, in
response to questions or otherwise. Any statements that express,
or involve discussions as to expectations, beliefs, plans,
objectives, assumptions or future events or performance (often, but
not always, through the use of words or phrases such as
"anticipates", "believes", "estimates", "expects", "intends",
"plans", "predicts", "projects", "will likely result", "will
continue", or similar expressions) are not statements of historical
facts and may be forward-looking. Forward-looking statements
involve estimates, assumptions, and uncertainties and are qualified
in their entirety by reference to, and are accompanied by, the
following important factors, which are difficult to predict,
contain uncertainties, are beyond our control and may cause actual
results to differ materially from those contained in forward-
looking statements:
- - prevailing governmental policies and regulatory actions,
including those of the Federal Energy Regulatory Commission (FERC),
the Idaho Public Utilities Commission (IPUC), the Oregon Public
Utilities Commission (OPUC), and the Public Utilities Commission of
Nevada (PUCN), with respect to allowed rates of return, industry
and rate structure, acquisition and disposal of assets and
facilities, operation and construction of plant facilities,
recovery of purchased power and other capital investments, and
present or prospective wholesale and retail competition (including
but not limited to retail wheeling and transmission costs):
- - economic and geographic factors including political and
economic risks;
- - changes in and compliance with environmental and safety laws
and policies;
- - weather conditions;
- - population growth rates and demographic patterns;
- - competition for retail and wholesale customers;
- - Year 2000 issues;
- - pricing and transportation of commodities;
- - market demand, including structural market changes;
- - changes in tax rates or policies or in rates of inflation;
- - changes in project costs;
- - unanticipated changes in operating expenses and capital
expenditures;
- - capital market conditions;
- - competition for new energy development opportunities; and
- - legal and administrative proceedings (whether civil or
criminal) and settlements that influence the business and
profitability of the Company.
Any forward-looking statement speaks only as of the date on which
such statement is made, and we undertake no obligation to update
any forward-looking statement to reflect events or circumstances
after the date on which such statement is made or to reflect the
occurrence of unanticipated events. New factors emerge from time
to time and it is not possible for management to predict all such
factors, nor can it assess the impact of any such factor on the
business or the extent to which any factor, or combination of
factors, may cause results to differ materially from those
contained in any forward-looking statement.
RESULTS OF OPERATIONS
Earnings per Share and Book Value
Earnings per share of common stock (basic and diluted) were $2.37
in 1998, $2.32 in 1997, and $2.21 in 1996. The 1998 earnings
equate to a 12.2 percent return on year-end common equity, as
compared to 12.2 percent in 1997 and 12.0 percent in 1996. At
December 31, 1998, the book value per share of common stock was
$19.42, compared to $18.93 at December 31, 1997 and $18.47 at
December 31, 1996.
Overview
A number of factors have contributed to the increase in earnings
per share over the last three years, including excellent
hydroelectric generating conditions, a strong service territory
economy, and continued cost management.
IPC's service territory experienced above average water years from
1996-1998. Hydro generation was 22 percent above normal in 1998,
30 percent above normal in 1997, and 18 percent above normal in
1996.
Idaho's economy continued its strong performance over the last
three years. Idaho's non-agricultural employment growth for the
twelve months ended November 1998 was 2.2 percent; annual growth
rates in 1997 and 1996 were 3.2 percent and 3.3 percent,
respectively. Within the Boise Metropolitan Statistical Area, the
heart of IPC's service territory, non-agricultural employment
increased 2.3 percent for the twelve months ended November 1998,
4.2 percent in 1997 and 3.9 percent in 1996.
General business customer growth continued in 1998, with a 2.9
percent increase, compared with a 3.0 percent increase in 1997 and
3.5 percent increase in 1996. This growth is attributable to
strong overall economic conditions in our service territory.
Operating revenues increased $373.5 million in 1998, and $170.1
million in 1997, due primarily to increased sales in the wholesale
electricity markets, increased rates, customer growth, and weather
conditions in our service territory.
As part of a regulatory settlement, IPC set aside approximately
$5.4 million in 1998, $7.6 million in 1997, and $4.9 million in
1996 for the benefit of our Idaho customers. We discuss the
regulatory settlement below in "Regulatory Issues - Regulatory
Settlement."
Total operating expenses increased $367.0 million in 1998 and
$172.5 million in 1997, due primarily to increased purchases in
wholesale electricity markets, and increased purchased power and
fuel costs resulting from increased sales.
Income taxes decreased $7.4 million from 1996 through 1998, due
primarily to an increase in tax credits earned from increasing
investments in affordable housing projects.
General Business Revenue
Our general business revenue is dependent on many factors,
including the number of customers we serve, the rates we charge,
and weather. The $34.4 million increase in general business
revenue in 1998 is due primarily to the annual change to the power
cost adjustment component of retail electric rates, other rate
adjustments, and to the 2.9 percent increase in general business
customers. We discuss the power cost adjustment below in
"Regulatory Issues - Power Cost Adjustment."
The $3.7 million decrease in general business revenue in 1997 is
due primarily to rate decreases, more moderate temperatures and
increased precipitation, which reduced average irrigation customer
energy sales by 8.2 percent and average residential customer energy
sales by 1.2 percent. Precipitation increased 37.1 percent during
the 1997 growing season, compared to 1996, and heating and cooling
degree days, a common measure used in the electric utility industry
to analyze usage, decreased by 3.3 percent in 1997. These factors
were partially offset by a 3.0 percent increase in the number of
general business customers.
Off-System Sales
Off-system sales are comprised of sales in the wholesale
electricity markets, long-term contracts, and opportunity sales
made when market prices make it cost-effective. The volume and
price of these latter sales depend on our firm energy demand,
hydroelectric generating conditions in our service territory, and
market conditions throughout the western United States.
Off-system sales increased $336.1 million in 1998 and $173.7
million in 1997. These increases relate primarily to increases in
the market price of electricity and sales in the wholesale
electricity markets. Off-system MWh sales increased 86 percent in
1998 and 201 percent in 1997. Increases in market prices increased
our average price per MWh sold by 28 percent in 1998 and 16 percent
in 1997.
Expenses
Purchased power expense increased $321.0 million in 1998 and $150.2
million in 1997 due primarily to an increase in purchases in the
wholesale electricity markets. Total MWhs of purchased power
increased 113 percent in 1998 and 213 percent in 1997. These
increases reflect our increased focus on the wholesale electricity
markets and the availability of low cost energy resulting from the
abundance of hydro generation in the West.
Fuel expense increased by $15.0 million in 1998 and $7.9 million in
1997 due primarily to increased generation at our coal-fired plants
to take advantage of off-system sales opportunities. Total
generation at the coal-fired plants was approximately 6.9 million
MWhs in 1998, 5.4 million MWhs in 1997 and 4.8 million MWhs in
1996.
The PCA mechanism increases expenses when power supply costs are
below forecast, and decreases expenses when power supply costs are
above forecast. In 1998, the PCA expense increased $27.9 million
because our 1998 power supply costs were well below the forecast,
where in 1997 they were somewhat above the forecast. The 1998
forecast had anticipated near-normal streamflow conditions in the
1998-9 rate period, but conditions have been significantly better
than normal. We discuss the PCA in more detail in "Regulatory
Issues - Power Cost Adjustment."
The increases in other operation expenses in 1998 and 1997 were due
primarily to increased payroll and benefits and increased
transmission charges for electricity sold.
Maintenance expenses decreased $6.9 million in 1998 and increased
$6.0 million in 1997. The decrease in 1998 results from decreased
maintenance expense at our steam generation facilities and
distribution facilities. The 1997 increase is due to extensive
maintenance at our steam generation facilities due to increased
utilization, and repairs to hydro facilities and distribution
facilities damaged by natural causes.
Other Income
Other income decreased $6.2 million in 1998 due primarily to costs
incurred by new subsidiaries and costs of other diversified
business activities. These subsidiaries and activities were
created to compete in the non-regulated business environment.
Income Taxes
Income taxes decreased $1.8 million in 1998 and $5.6 million in
1997. The decrease in 1998 is due primarily to an increase in
affordable housing tax credits. The decrease in 1997 is due
primarily to an increase in affordable housing tax credits and
decreased net income before taxes.
Regulatory Issues
Power Cost Adjustment (PCA)
IPC has a PCA mechanism that provides for annual adjustments to the
rates we charge to our Idaho retail customers. These adjustments,
which take effect annually on May 16, are based on forecasts of net
power supply costs and the true-up of the prior year's forecast.
The difference between the actual costs incurred and the forecasted
costs is deferred, with interest, and trued-up in the next annual
rate adjustment.
The May 1998 adjustment to rates includes the deferred costs from
the 1997-98 PCA year as well as the difference between base power
supply cost assumptions and forecasted power supply costs. The
1998-99 forecast assumed a return to more normal hydroelectric
generating conditions. This resulted in forecasted power supply
costs being near the amounts used to establish base rates in past
regulatory proceedings. The May 1998 rate adjustment increases
expected annual revenue by $34.0 million over the amount that would
have been received at the 1997 rates, and $17.3 million over what
would be recovered if we were charging the base rates during this
rate period.
So far in the current rate period, actual power costs have been
less than forecast, due to better than forecast hydroelectric
generating conditions. We have recorded a reduction to regulatory
assets of $10.4 million as of December 31, 1998. The variance that
exists at the end of the 1998-99 rate period will be trued-up in
the next annual PCA adjustment.
Regulatory Settlement
IPC has a settlement agreement with the IPUC that remains in effect
through 1999. Under the terms of the settlement, when our actual
earnings in a given year exceed an 11.75 percent return on year-end
common equity for the Idaho jurisdiction, we will set aside 50
percent of the excess for the benefit of our Idaho retail
customers. In 1998, we set aside $5.4 million for the benefit of
our Idaho customers, compared to $7.6 million in 1997 and $4.9
million in 1996. We requested that approximately $5.0 million of
the 1997 earnings sharing amount be applied against the balance of
deferred demand-side conservation expenditures in order to defer
any rate increases associated with the conservation recovery until
May 16, 1999, the same date as the next PCA adjustment.
In addition, the settlement allows for the accelerated amortization
of regulatory liabilities associated with accumulated deferred
investment tax credits (ADITCs), up to a maximum of $30 million, to
provide a minimum 11.50 percent return on actual year-end common
equity for the Idaho jurisdiction.
We have received approval from the Idaho State Tax Commission and
the Internal Revenue Service on the accounting treatment for the
tax credits. As of December 31, 1998, no ADITCs have been used
under the regulatory agreement.
Other important points in the settlement are that we will not be
allowed to increase our Idaho general rates prior to January 1,
2000, except under special conditions as defined in the Settlement
Agreement, and that we agree that our quality of service will not
decline as a result of corporate reorganization.
Demand-Side Management (Conservation) Expenses
We are seeking changes to the regulatory treatment of previously
deferred demand-side management (DSM) expenses in both Idaho and
Oregon.
In Idaho, we requested the IPUC to authorize recovery of post-1993
DSM expenses and acceleration of the recovery of DSM expenditures
authorized in the last general rate case. We requested a five-year
amortization instead of the 24-year period previously adopted. In
its Order No. 27660 issued on July 31, 1998, the IPUC set a new
amortization period of 12 years. The IPUC order reflects an
increase in annual Idaho retail revenue requirements of $3.1
million for 12 years.
As noted above, we are funding the annual revenue requirement with
revenue sharing amounts until May 16, 1999. A group of our
industrial customers has appealed the IPUC order to the Idaho
Supreme Court.
In December 1998 we filed with the IPUC, a request to recover our
remaining deferred DSM expenditures of approximately $2.0 million.
The IPUC has set this case for hearing in March 1999. In our
filing we requested that the amount be applied against 1998
earnings sharing amounts.
In Oregon, the OPUC authorized the amortization of the Oregon-
allocated share of the DSM expenditures over five years. The DSM
charge replaces an expiring rate surcharge related to extraordinary
power supply costs associated with past drought conditions. We
anticipate that the charge will recover approximately $540,000 per
year.
Ida-West Energy Company
Ida-West Energy Company, a wholly owned subsidiary of IDACORP, was
formed in 1989 to develop, finance, construct, acquire, own and
operate electric power generation facilities. Ida-West is actively
marketing new projects to utilities located in the West and is
seeking to acquire operating facilities and projects under
development throughout the United States and Canada. Existing Ida-
West projects produced over 302,000 MWh's of energy in 1998.
In addition, Ida-West has an interest in the Hermiston Power
Project, a 536 MW, gas-fired cogeneration project to be located
near Hermiston, Oregon. Ida-West has been responsible for managing
all permitting and development activities relating to the project
since its inception in 1993, and has obtained all permits necessary
for construction and operation of the project. The partnership is
exploring various alternatives for marketing the project's output.
To date, we have invested $20 million in Ida-West.
IDACORP Financial Services, Inc. (IFS)
IFS, a wholly owned subsidiary of IPC, participates in 12
affordable housing programs. These investments provide a return by
reducing our federal income taxes and by assuring a return on
investment through tax credits and tax depreciation benefits. To
date, we have invested $6.5 million in IFS.
LIQUIDITY AND CAPITAL RESOURCES
Cash Flow
Our net cash generated from operations totaled $508.6 million for
the three-year period 1996-1998. After deducting common dividends
of $209.7 million, net cash generation from operations provided
approximately $298.9 million for our construction program and other
capital requirements. Internal cash generation after dividends
provided 95 percent of our total capital requirements in 1998, 89
percent in 1997, and 74 percent in 1996.
In 1998, we increased our cash and cash equivalents by $12.2
million from life insurance death benefits and the surrender of
life insurance policies.
We forecast that internal cash generation after dividends will
provide approximately 80 percent of total capital requirements in
1999 and over 94 percent during the four-year period 2000-2003. We
expect to continue financing our construction program and other
capital requirements with both internally generated funds and, to
the extent necessary, externally financed capital. Principal
amounts maturing during the forecast period are $6.0 million in
1999, $86.5 million in 2000, $36.9 million in 2001, $34.1 million
in 2002 and $86.5 million in 2003.
At January 1, 1999, IPC had regulatory authority to incur up to
$200.0 million of short-term indebtedness. At December 31, 1998,
its short-term borrowing totaled $38.5 million compared to $57.5
million at December 31, 1997 and $54.0 million at December 31,
1996.
On December 19, 1996, IPC replaced its committed lines of credit
arrangements with a $120.0 million multi-year revolving credit
facility under which we pay a facility fee on the commitment,
quarterly in arrears, based on IPC's First Mortgage Bond Rating.
On December 21, 1998, IDACORP established a $100.0 million 364-day
credit facility which will expire December 19, 1999, and a $50.0
million 3-year credit facility which will expire December 21, 2001.
Under these facilities we will pay a facility fee on the
commitment, quarterly in arrears, based on IPC's First Mortgage
Bond Rating. Commercial paper may be issued up to $150.0 million
and is supported by the bank credit facilities. (See Note 7 of
"Notes to Consolidated Financial Statements").
Construction Program
Our consolidated cash construction expenditures totaled $89.2
million in 1998, $95.6 million in 1997, and $93.6 million in 1996.
Approximately 27 percent of these expenditures were for generation
facilities, 14 percent for transmission facilities, 44 percent for
distribution facilities, and 15 percent for general plant and
equipment. We estimate that our cash construction program will
require $115 million in 1999 and $527 million in the four-year
period 2000-2003. These estimates are subject to revision in light
of changing economic, regulatory, environmental, and conservation
factors.
Financing Program
Our capital structure fluctuated slightly during the three-year
period, with common equity ending at 44 percent, preferred stock
(of IPC) seven percent, and long-term debt 49 percent at December
31, 1998.
IDACORP, Inc. currently has a $300.0 million shelf registration
statement that can be used for the issuance of unsecured debt
securities and preferred or common stock. IDACORP also has
committed short-term credit arrangements totaling $150.0 million.
At December 31, 1998, none had been issued.
IPC has on file a shelf registration statement for the issuance of
first mortgage bonds and/or preferred stock, with an aggregate
principal amount not to exceed $200 million. In September 1998 IPC
issued $60 million of Secured Medium Term Notes. The proceeds from
this issuance were used to redeem at maturity $30 million of First
Mortgage Bonds, and to reduce the balance of commercial paper
issued in connection with ongoing business.
In 1996, IPC issued $57 million of Secured Medium Term Notes. The
net proceeds were used for repayment of commercial paper issued in
connection with our ongoing construction program and to redeem
preferred stock. These transactions have reduced the remaining
balance on the shelf registration to $83 million as of December 31,
1998.
In August 1996, IPC issued tax exempt Pollution Control Revenue
Refunding Bonds with a principal amount of $116.3 million. The
proceeds were used to retire the $116.3 million of Pollution
Control Revenue Bonds due between 2003 and 2014.
OTHER MATTERS
Environmental Issues
Salmon Recovery Plan
We are continuing to work on the development of a comprehensive and
scientifically credible plan to ensure the long-term survival of
anadromous fish runs on the Columbia and Lower Snake rivers.
In mid-August 1994, the federal government changed its designation
of the Fall Chinook Salmon from Threatened to Endangered. We do
not anticipate that the new designation will have any major effects
on our operations.
In September 1991, we modified operations at our three-dam Hells
Canyon Hydroelectric Complex to protect the Fall Chinook downstream
during spawning and juvenile emergence. From its start, our Fall
Chinook program has exceeded the protection requirements for
threatened species, affording the fish the same high level of
protection due an endangered species.
In March of 1995, the National Marine Fisheries Service (NMFS)
released a Proposed Recovery Plan for the listed Snake River
Salmon. The NMFS accepted public comment on the Plan through
December of 1995. As drafted, the Plan would not require any
change to our current operations for salmon. Pending completion of
a final recovery plan by the NMFS, the U.S. Army Corps of Engineers
and other governmental agencies operating federally owned dams and
reservoirs on the Snake and Columbia Rivers will continue to
consult with the NMFS regarding ongoing system operations. These
interim operations are not expected to change our current
operations for salmon.
The Northwest Power Planning Council (NWPPC) issued its recovery
plan for Snake River anadromous fish, the Strategy for Salmon, on
December 15, 1994. The NWPPC plan called for the U.S. Bureau of
Reclamation (BOR) to acquire 500,000 acre-feet of water within the
Snake River Basin by 1996, and an additional 500,000 acre-feet by
1998. The water is to be acquired from willing sellers. Thus far,
the BOR has not complied with the request to acquire 1,000,000 acre-
feet of additional water. However, if the BOR does comply and
successfully implements the request, its movement of additional
water could have a material impact on our power supply costs. IPC
and the BPA have negotiated a five-year contract, expiring April
15, 2001, requiring BPA to replace lost energy and capacity
resulting from recovery plans that impact our power supply cost.
Nez Perce Lawsuit
On March 21, 1997, the United States District Court for the
District of Idaho entered a judgment related to a civil lawsuit
filed against IPC in 1991 by the Nez Perce Tribe. The suit arose
from the construction, maintenance, and operation of our three-dam
Hells Canyon Complex and the project's alleged impact both on fish
and the Tribe's treaty-reserved fishing rights. The judgment,
which incorporated the terms of an agreement already reached by IPC
and the Tribe, requires us to pay the Nez Perce Tribe $11.5 million
over five years. All payments under the Agreement will be made in
1996 dollars, which allows for adjusted future inflation within a
minimum range of three percent and a maximum of seven percent. As
of December 31, 1998, $4.9 million remains payable to the Tribe
over the next three years.
On July 12, 1996, the IPUC issued Order No. 26513, and on August 5,
1996, the OPUC issued Order No. 96-207 approving capitalization of
their respective jurisdictional shares of the $11.5 million.
In connection with settling the litigation, IPC and the Tribe also
reached a provisional settlement regarding the license renewal of
the Hells Canyon Complex. In return for the Tribe's support of our
application to relicense the project, we will place $5 million, the
majority of which the Tribe has agreed to dedicate to implementable
fisheries restoration efforts, in an escrow account on August 3,
2003, the date by which we must file our relicense application.
The Tribe will be entitled to earnings from investments on this
account until we accept or reject a new federal license for the
project. If we accept the new federal license, the Tribe will take
ownership of the money in the account. If we reject the license,
the money will be returned to us. This settlement is provisional
because the Tribe retains the right to opt out of this relicensing
settlement at any time prior to our acceptance of a new federal
license.
Threatened and Endangered Snails
In December 1992, the U.S. Fish and Wildlife Service (USFWS) listed
five species of Snake River snails as Threatened and Endangered
Species. Since that time, we have included this possibility in all
of our discussions regarding relicensing and new hydro development.
The listing specifically mentions the impact that fluctuating water
levels related to hydroelectric operations may have on the snails
and their habitat. Although the hydro facilities on that reach of
the Snake River do not significantly affect water levels during
typical operations, some of them do provide the daily operational
flexibility to meet increased electricity demand during high load
hours. Recent studies suggest that this has no impact on the
listed snails. While it is possible that the listing could affect
how we operate our existing hydroelectric facilities on the middle
reach of the Snake River, we believe that such changes will be
minor and will not present any undue hardship.
In 1995, as a part of our federal hydro relicensing process, we
obtained a permit from the USFWS to study the five species of
endangered Snake River snails. Our biologists have completed
several studies to gain scientific insight into how or if these
snails are affected by a variety of factors, including hydropower
production, water quality, and irrigation run-off. Results of the
studies indicated that the snail colonies were part of a biological
community well adapted to the influences of hydropower, water
quality, and irrigation run-off. Company-sponsored studies
continue to review how these and other factors affect the status of
the various colonies and their habitats.
Clean Air Act
We have analyzed the Clean Air Act's effects on us and our
customers. Our coal-fired plants in Oregon and Nevada already meet
the federal emission rate standards for sulfur dioxide (SO2) and
our coal-fired plant in Wyoming meets that state's even more
stringent SO2 regulations. Therefore, we foresee no adverse
effects on our operations with regard to SO2 emissions.
Electric and Magnetic Fields
While scientific research has not established any conclusive link
between electric and magnetic fields (EMFs) and human health, the
possibility of a link has caused public concern in the United
States and abroad. Electric and magnetic fields exist wherever
there is electric current, whether the source is a high-voltage
transmission line or the simplest of electrical household
appliances. Concerns over possible health effects have prompted
regulatory efforts in several states to limit human exposure to
EMFs. Depending on what researchers ultimately discover and any
necessary regulations, it is possible that this issue could affect
a number of industries, including electric utilities. However, it
is difficult at this time to estimate what effects, if any, the EMF
issue could have on us and our operations.
Electric Industry Restructuring
Competition is increasing in the electric utility industry. Our
goal is to anticipate and fully integrate into our operations any
legislative, regulatory or competitive changes. We are pursuing a
rapid, but orderly transition to at least a partially and possibly
a totally deregulated environment in the years ahead. The
following items describe some of the changes to date, as well as
steps we are taking.
Legislative Actions
In 1997, the Idaho Legislature appointed a committee to study
restructuring of the electric utility industry. Legislation
resulting from this committee required the IPUC to begin an
investigation into the unbundling of costs into its various
delivery and energy components. We filed cost unbundling studies
in July and December 1997. The IPUC compiled cost data presented
by all the electric utilities and presented that information to the
legislature. Although the committee will continue studying a
variety of restructuring ideas, it is not expected to recommend
restructuring legislation in the foreseeable future.
FERC Decisions
On April 24, 1996, the FERC issued its Order Nos. 888 and 889
dealing with Open-Access Non-Discriminatory Transmission Services
by Public and Transmitting Utilities, and standards of conduct
regarding these issues. These orders require public utilities
owning transmission lines to file open-access tariffs available to
buyers and sellers of wholesale electricity; to require utilities
to use the tariffs for their own wholesale sales; and to allow
utilities to recover stranded costs, subject to certain conditions.
Public utilities owning transmission lines were required to file
compliance tariffs by July 9, 1996.
In November 1995, we filed open-access tariffs with the FERC for
Point-to-Point and Network transmission service. The substance of
these tariffs was to offer the same quality and character of
transmission services that we use in our own operations to anyone
seeking them. We requested and received permission to implement
these tariffs beginning February 1, 1996. On July 8, 1996, we
filed a new open-access transmission tariff to replace the 1995
tariffs. This provides full compliance with Final Order No. 888.
This filing did not include a rate change. On November 13, 1996,
FERC issued an unconditional acceptance of the terms and conditions
of this tariff. The rate was not subject to review.
Energy Trading
We intend to be a competitive energy provider, including both
electricity and natural gas. In mid-1997, IPC opened a gas trading
office in Houston, Texas, to serve the southern and eastern United
States and a Boise, Idaho office to serve the Northwest and
Canadian markets. We also participate in the western wholesale
electricity markets, the results of which are included in off-
system revenue and purchased power expense.
Inherent in the energy trading business are risks related to market
movements and the creditworthiness of counterparties. When buying
and selling energy, the high volatility of energy prices can have a
significant impact on profitability if not managed. Also,
counterparty creditworthiness is key to ensuring that transactions
entered into withstand dramatic market fluctuations.
To mitigate these risks while implementing our business strategy,
the IPC Board of Directors gave approval for executive management
to form a Risk Management Committee, comprised of Company officers,
to oversee a risk management program. The program is intended to
minimize fluctuations in earnings while managing the volatility of
energy prices. Embedded within the Risk Management policy and
procedures is a credit policy requiring ongoing evaluation of the
financial condition of counterparties, the securitization of credit
support where needed, and ongoing monitoring of credit exposure.
The objective of our risk management program is to mitigate
commodity price risk, credit risk, and other risks related to the
energy trading business.
Market Rate Sensitive Instruments and Risk Management
The following discussion summarizes the financial instruments,
derivative instruments and derivative commodity instruments
sensitive to changes in interest rates and commodity prices that
IPC held at December 31, 1998. IPC buys and sells financial and
physical natural gas and electricity commodity contracts as part of
our ongoing business. These contracts are subject to electricity
and natural gas commodity price risk. We have a trading and risk
management policy defining the limits within which we contain our
commodity price risk. We trade commodity futures, options and
swaps as a method of managing the commodity price risk associated
with electricity and natural gas trading. We have minimal foreign
exchange exposure related to natural gas trading activities in
Canadian dollars. This exposure is periodically offset through the
use of foreign exchange swap instruments. Our sensitivity related
to foreign exchange rate fluctuations as of December 31, 1998, is
immaterial.
Interest Rate Risk Sensitivity
This table presents descriptions of our financial instruments at
December 31, 1998, that are sensitive to changes in interest rates.
We did not hold any interest rate derivative instruments at
December 31, 1998. The majority of our debt is held in fixed rate
securities with embedded call options. We hold $48.2 million in
variable-rate tax-exempt debt for pollution control financings and
4.5 percent of our total debt is variable in the form of commercial
paper. The variable rate debt is not interest rate sensitive by
nature and the commercial paper borrowings do not give rise to
significant interest rate risk because these borrowings generally
have maturities of less than three months.
The table below presents principal cash flows by maturity date and
the related average interest rate. The table also presents the
fair value for all fixed rate instruments as of December 31, 1998,
based on market rates for similar instruments as of that date.
Expected Maturity Date
1999 2000 2001 2002 2003 Thereafter Total Fair Value
Fixed rate debt
(in millions) $ 6.0 $87.8 $38.4 $35.7 $88.2 $519.3 $775.4 $829.2
Average
interest rate 7.52% 8.55% 7.05% 7.00% 6.50% 7.76% 7.64%
Commodity Price Risk Sensitivity
This analysis presents the estimated December 31, 1998 value-at-
risk related to our energy commodity contracts and related
derivative instruments that are sensitive to changes in commodity
prices. We use commodity derivative instruments such as futures,
options and swaps to hedge against exposure to commodity price risk
in the electricity and natural gas markets. The objective of our
hedging program is to mitigate the risk associated with the
purchase and sale of natural gas and electricity. Company policy
also allows the use of these commodity derivative instruments for
trading purposes in support of our operations.
The aggregate potential loss in earnings from our energy trading
activity is estimated to be $500,000 at a 95-percent confidence
interval and for a holding period of one business day. The
potential loss in earnings was estimated using a value-at-risk
methodology with a monte carlo simulation. The monte carlo
simulation averages outcomes from multiple scenarios based on our
exposure at December 31, 1998. The multiple scenarios assume
potential commodity prices based on historical prices, volatility
and correlations to generate outcomes. Limitations of the value-at-
risk analysis arise from uncertainties in assumptions. Historical
prices, volatility and correlations are not necessarily a predictor
of future prices, volatility and correlations. The use of a 95
percent confidence interval implies there is a 2.5 percent chance
the value-at-risk is greater than that which is stated. A holding
period of one day implies that all exposures could be liquidated in
one business day. A lack of liquidity in the market could result
in a holding period of more than one day.
Relicensing of Hydroelectric Projects
We are actively pursuing the relicensing of our hydroelectric
projects, a process that will continue for the next 10 to 15 years.
We submitted our first applications for license renewal to the FERC
in December 1995. We have now filed applications seeking renewal
of our licenses for our Bliss, Upper Salmon Falls, Lower Salmon
Falls, C J Strike and Shoshone Falls Hydroelectric Projects.
Although various federal requirements and issues must be resolved
through the license renewal process, we anticipate that our efforts
will be successful. At this point, however, we cannot predict what
type of environmental or operational requirements we may face, nor
can we estimate the eventual cost of license renewal. At December
31, 1998, $10.7 million of relicensing costs were included in
Construction Work in Progress.
Year 2000 Costs
Many existing computer systems use only two digits to identify a
year in the date field. These programs were designed and developed
without considering the impact of the upcoming change in the
century. Unless proper modifications are made, the program logic
in many of these systems will start to produce erroneous results
because, among other things, the systems will read the date
"01/01/00" as being January 1 of the year 1900 or another incorrect
date. In addition, the systems may fail to detect that the year
2000 is a leap year. Similar problems could arise prior to the
year 2000 as dates in the next millennium are entered into systems
that are not Year 2000 compliant.
We recognize the Year 2000 problem as a serious threat to the
Company and our customers. Our Year 2000 effort has been underway
for over two years and is being addressed at the highest levels
within the Company. The IPC Vice President of Corporate Services
is responsible for coordinating the corporate effort. Each IPC
vice president is responsible for addressing the problem within
their respective business units and each has assigned a Year 2000
Project Leader to execute the project plan. Each subsidiary
President is responsible for addressing the problem within their
subsidiary in coordination with the corporate effort. In addition,
we have appointed a full-time Year 2000 Project Manager to direct
the project. Additional staff has been committed to complete the
conversion and implementation needed to bring non-compliant items
into compliance. This staff consists of a mix of end users, IPC
Information Services staff and contract programmers. Currently,
there are over 20 full-time employees devoted to the project with
dozens of others involved to varying degrees. We have retained
third parties who have recently completed technical and legal
audits of our plan. With respect to the technical audit, we have
completed our review of the audit report, have begun implementation
of most of the recommendations and are discussing the remainder of
the recommendations with the auditing company. Regarding the legal
audit, we have received a draft audit and are presently reviewing
the draft report internally.
We have targeted July 1999 as the date by which we expect to be
ready for the Year 2000. This means that all critical systems are
expected to be capable of handling the century rollover and that we
will be able to continue servicing our customers without
interruption. It also means that all of the less critical systems
are expected to have been identified and that contingency and/or
repair plans are expected to be in place for dealing with the
change of century.
We are following a detailed project plan. The methodology is
modeled after those used by some of the top companies in the world
and has been adapted to meet our unique requirements. This process
includes all the phases and steps commonly found in such plans,
including the (i) identification and analysis of critical systems,
key manufacturers, service providers, embedded systems, generation
plants (part of which is owned by the Company but is operated by
another electric utility), (ii) remediation and testing,
(iii) education and awareness and (iv) contingency planning.
With respect to that key component of the methodology related to
the identification of critical systems, we have identified those
critical systems which must be Year 2000 compliant in order to
continue operations. Many are already compliant or are in the
process of vendor upgrades to become compliant. The largest of
these critical systems and their status regarding compliance are
set forth below:
System Description Status
Business The business systems include the Our testing
Systems financial and administrative has shown
functions common to most companies. PeopleSoft and
Business systems include accounts PassPort both
payable, general ledger, accounts to be
receivable, labor entry, inventory, compliant
purchasing, cash management, vendor
budgeting, asset management, packages.
payroll, and financial reporting.
Customer This system is used to, among other In-house
Information things, bill customers, log calls system has
System from customers and create service or been repaired.
work requests and track them through Testing is
completion. At this time, the underway.
Company uses an in-house developed,
mainframe-based Customer Information
System to accomplish these tasks.
Energy The most critical function the The packages
Management Company offers is the delivery of comprising the
System (EMS) electricity from the source to the EMS are now
consumer. This must be done with fully
minimal interruption in the midst of compliant and
high demand, weather anomalies and rollout is
equipment failures. To accomplish underway.
this, we rely on a server-based Testing is
energy management system provided by currently
Landis & Gyr. This system monitors underway.
and directs the delivery of
electricity throughout our service
area.
Metering We rely on several processes for In-house code
Systems metering electricity usage, has been
including some hand-held devices repaired.
with embedded chips. It is critical Vendor
for metering systems to operate packages are
without interruption so as not to being
jeopardize our revenue stream. upgraded.
Testing is
underway.
Embedded There is a category of systems on Non-Year 2000
Systems which the Company is highly reliant compliant
called embedded systems. These are chips have
typically computer chips that been replaced.
provide for automated operations Test bench has
within some device other than a been
computer such as a relay or a established.
security system. We are highly Testing is
reliant on these systems throughout about 75%
our generation and delivery systems complete.
to monitor and allow manual or
automatic adjustments to the desired
devices.
Other We also rely on a number of other In various
Systems important systems to support stages of
engineering, human resources, safety repair and
and regulatory compliance, etc. testing.
Regarding third parties, the plan methodology has required us to
identify those third parties with which we have a material
relationship. We have identified as material (1) our ownership
interest in thermal generating facilities which are operated and
maintained by third party electric utilities; (2) our fuel
suppliers for those thermal generating facilities; and (3) our
telecommunication providers. In addition, we have identified
ninety-three (93) key manufacturers that provide materials and
supplies to us. With respect to the thermal plants, fuel suppliers
and telecommunication providers, the plan methodology includes a
process wherein some members of the Year 2000 team meet
periodically with the third parties to assess the status of their
efforts. This is an ongoing process and will continue until such
time as the third party has completed compliance testing and
certified to us that they are compliant. Regarding the 93 key
manufacturers, we have contacted all via mail and requested they
complete a survey indicating the extent and status of their Year
2000 efforts. The survey is followed up with contact by telephone
to further document their Year 2000 status.
Finally, we are connected to an electric grid that connects
utilities throughout the western portion of North America. This
interconnection is essential to the reliability and operational
integrity of each connected utility. This also means that failure
of one electric utility in the interconnected grid could cause the
failure of others. In the context of the Year 2000 problem, this
interconnectivity compounds the challenge faced by the electric
utility industry. Our Company could do a very thorough and
effective job of becoming Year 2000 compliant and yet encounter
difficulties supplying services and energy because another utility
in the interconnected grid failed to achieve Year 2000 compliance.
In this regard, we are working closely with other electric industry
organizations concerned with reliability issues and technical
collaboration.
Our estimate of the cost of our Year 2000 plan remains at
approximately $5.3 million which is being expensed as incurred.
This includes costs incurred to date (approximately $1.8 million)
and estimated costs through the year 2000. This level of
expenditure is not expected to have a material effect on our
operations or our financial position. Funds to cover Year 2000
costs in 1999 have been budgeted by business unit, subsidiary and
within the IPC Information Services Department with approximately
10 percent of the IPC Information Services budget used for
remediation. No IPC Information Services Department projects have
been deferred due to our year 2000 efforts.
The Year 2000 issue poses risks to our internal operations due to
the potential inability to carry on our business activities and
from external sources due to the potential impact on the ability of
our customers to continue their business activities. The major
applications that pose the greatest risks internally are those
systems, embedded or otherwise, which impact the generation,
transmission and distribution of energy and the metering and
billing systems. The potential risks related to these systems are
electric service interruptions to customers and associated
reduction in loads and revenue, and interrupted data gathering and
billing, and the resultant delay in receipt of revenues. All of
this would negatively impact our relationship with our customers,
which may enhance the likelihood of losing customers in a
restructured industry. Externally, those customers who
inadequately prepare for the Year 2000 issue may be unable to
continue their business activities. This would affect us in a
number of ways. Our loads and revenue would be reduced because of
the lost load from discontinued business activities, and customers
who lose jobs because of discontinued business activities may face
difficulties in paying their power bills. The impact of this on us
is dependent upon the number and the size of those businesses that
are forced to discontinue business activities because of the Year
2000 issue.
As part of our Year 2000 plan, we are in the process of developing
a contingency plan and expect to complete this process on or before
July 1999.
Management Changes
In January 1999 IDACORP's Board of Directors approved the
retirement plans of Chairman of the Board of Directors and Chief
Executive Officer Joseph W. Marshall. Mr. Marshall will retire
effective June 1, 1999, and Jan B. Packwood, currently serving as
President, will assume the responsibilities of Chief Executive
Officer. Jon Miller, a Board member since 1988, will replace
Marshall as Chairman of the Board in a non-executive capacity.
New Accounting Pronouncements
In June 1998, the FASB issued SFAS No. 133 "Accounting for
Derivative Instruments and Hedging Transactions." This statement
establishes accounting and reporting standards for derivative
financial instruments and other similar financial instruments and
for hedging activities. It is effective for fiscal years beginning
after June 15, 1999. We are reviewing this statement to determine
its effect on our financial position and results of operations.
Emerging Issues Task Force 98-10 (EITF 98-10), "Accounting for
Contracts Involved in Energy Trading and Risk Management
Activities" is issued and effective for financial statements for
fiscal years beginning after December 15, 1998. We anticipate the
impact of adoption on our financial position and results of
operations will be immaterial.
ITEM 7a. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET
RISK
The information required by this item is included in Item 7
"Management's Discussion and Analysis of Financial Condition and
Results of Operations" under "Market Rate Sensitive Instruments and
Risk Management"
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES
PAGE
Management's Responsibility for Financial Statements 38
Consolidated Financial Statements:
IDACORP, Inc.
Consolidated Statements of Income for the Years Ended
December 31, 1998, 1997 and 1996 39
Consolidated Balance Sheets as of December 31, 1998,
1997 and 1996 40-41
Consolidated Statements of Capitalization as of December 31,
1998, 1997 and 1996 42
Consolidated Statements of Cash Flows for the Years Ended December
31, 1998, 1997 and 1996 43
Consolidated Statements of Retained Earnings and Consolidated
Statements of
Comprehensive Income for the Years Ended December 31, 1998,
1997 and 1996 44
Notes to Consolidated Financial Statements 45-59
Independent Auditors' Report 60
Idaho Power Company
Consolidated Statements of Income for the Years Ended December 31,
1998, 1997 and 1996 61
Consolidated Balance Sheets as of December 31, 1998, 1997 and
1996 62-63
Consolidated Statements of Capitalization as of December 31, 1998,
1997 and 1996 64
Consolidated Statements of Cash Flows for the Years Ended December
31, 1998, 1997 and 1996 65
Consolidated Statements of Retained Earnings and Consolidated
Statements of
Comprehensive Income for the Years Ended December 31, 1998, 1997
and 1996 66
Notes to Consolidated Financial Statements 67-69
Independent Auditors' Report 70
Supplemental Financial Information and Financial Statement
Schedules:
Supplemental Financial Information (Unaudited) 71
Financial Statement Schedules for the Years Ended December 31,
1998, 1997 and 1996:
Schedule II-Consolidated Valuation and Qualifying Accounts-
IDACORP, Inc. 77
Schedule II-Consolidated Valuation and Qualifying Accounts-Idaho
Power Company. 77
MANAGEMENT'S RESPONSIBILITY FOR FINANCIAL STATEMENTS
The management of IDACORP, Inc. and Idaho Power Company is
responsible for the preparation and presentation of the information
and representations contained in the accompanying financial
statements. The financial statements have been prepared in
conformance with generally accepted accounting principles. Where
estimates are required to be made in preparing the financial
statements, management has applied its best judgment as to the
adequacy of the estimates based upon all available information.
The Companies maintain systems of internal accounting controls and
related policies and procedures. The systems are designed to
provide reasonable assurance that all assets are protected against
loss or unauthorized use. Also, the systems provide that
transactions are executed in accordance with management's
authorization and properly recorded to permit preparation of
reliable financial statements. The systems are supported by a
staff of corporate accountants and internal auditors who, among
other duties, evaluate and monitor the systems of internal
accounting control in coordination with the independent auditors.
The staff of internal auditors conducts special and operational
audits in support of these accounting controls throughout the year.
Each Company's Board of Directors, through their Audit Committees
comprised entirely of outside directors, meet periodically with
management, internal auditors and independent auditors to discuss
auditing, internal control and financial reporting matters. To
ensure their independence, both the internal auditors and
independent auditors have full and free access to the Audit
Committees.
The financial statements have been audited by Deloitte & Touche
LLP, the Companies' independent auditors, who were responsible for
conducting their audit in accordance with generally accepted
auditing standards.
Joseph W. Marshall
Chairman and Chief Executive Officer
J. LaMont Keen
Vice President, Chief Financial Officer and Treasurer
IDACORP, Inc.
Consolidated Statements of Income
Year Ended December 31,
1998 1997 1996
(Thousands of Dollars except for
per share amounts)
REVENUES:
General business $ 514,856 $ 480,458 $ 484,145
Off system sales 579,984 243,874 70,222
Other revenues 27,136 24,171 24,078
Total revenues 1,121,976 748,503 578,445
EXPENSES:
Operation:
Purchased power 540,200 219,200 69,038
Fuel expense 86,237 71,271 63,334
Power cost adjustment 21,866 (6,032) (6,859)
Other 145,374 137,458 132,667
Maintenance 41,872 48,722 42,731
Depreciation 74,481 71,973 69,705
Taxes other than income
taxes 20,725 21,162 20,658
Total expenses 930,755 563,754 391,274
INCOME FROM OPERATIONS 191,221 184,749 187,171
OTHER INCOME:
Allowance for equity funds 300 34 46
used during construction
Gas trading activities -
Net (3,208) (1,181) -
Other - Net 10,928 15,402 12,488
Total other income 8,020 14,255 12,534
INTEREST EXPENSE AND OTHER:
Interest on long-term debt 52,270 53,215 52,165
Other interest 8,407 7,546 5,183
Allowance for borrowed funds
used during (900) (503) (353)
construction
Preferred dividends of Idaho 5,658 5,176 7,463
Power Company
Total interest expense 65,435 65,434 64,458
and other
INCOME BEFORE INCOME TAXES 133,806 133,570 135,247
INCOME TAXES 44,630 46,472 52,092
NET INCOME $ 89,176 $ 87,098 $ 83,155
AVERAGE COMMON SHARES
OUTSTANDING (000) 37,612 37,612 37,612
EARNINGS PER SHARE OF
COMMON STOCK (basic and
diluted) $ 2.37 $ 2.32 $ 2.21
The accompanying notes are an integral part of these statements.
IDACORP, Inc.
Consolidated Balance Sheets
Assets
December 31,
1998 1997 1996
(Thousands of Dollars)
ELECTRIC PLANT:
In service (at original cost) $2,659,441 $2,605,697 $2,537,565
Accumulated provision for
depreciation (1,009,387) (942,400) (886,885)
In service - Net 1,650,054 1,663,297 1,650,680
Construction work in progress 59,717 51,892 42,178
Held for future use 1,738 1,738 1,773
Electric plant - Net 1,711,509 1,716,927 1,694,631
INVESTMENTS AND OTHER PROPERTY 129,437 97,065 69,903
CURRENT ASSETS:
Cash and cash equivalents 22,867 6,905 7,928
Receivables:
Customer 81,245 63,076 34,962
Allowance for uncollectible
accounts (1,397) (1,397) (1,394)
Gas trading 21,426 42,128 -
Notes 4,643 4,613 5,104
Employee notes 4,510 4,757 4,486
Other 6,059 8,854 8,489
Accrued unbilled revenues 34,610 33,312 27,709
Materials and supplies (at
average cost) 30,157 29,156 24,639
Fuel stock (at average cost) 7,096 7,172 11,631
Prepayments 16,042 15,381 16,165
Regulatory assets associated 2,965 3,164 4,397
with income taxes
Total current assets 230,223 217,121 144,116
DEFERRED DEBITS:
American Falls and Milner water
rights 31,830 32,055 32,260
Company-owned life insurance 35,149 51,915 57,291
Regulatory assets associated
with income taxes 201,465 198,521 196,696
Regulatory assets - other 62,013 90,239 89,507
Other 49,994 47,973 44,334
Total deferred debits 380,451 420,703 420,088
TOTAL $2,451,620 $2,451,816 $2,328,738
The accompanying notes are an integral part of these statements.
IDACORP, Inc.
Consolidated Balance Sheets
Capitalization and Liabilities
December 31,
1998 1997 1996
(Thousands of Dollars)
CAPITALIZATION:
Common stock equity:
Common stock without par
value (shares authorized
120,000,000; shares
outstanding - 37,612,351) $ 451,564 $ 452,519 $ 452,486
Retained earnings 278,607 259,299 242,088
Accumulated other
comprehensive income 226 - -
Total common stock equity 730,397 711,818 694,574
Preferred stock of Idaho Power
Company 105,968 106,697 106,975
Long-term debt 815,937 746,142 769,810
Total capitalization 1,652,302 1,564,657 1,571,359
CURRENT LIABILITIES:
Long-term debt due within one 6,029 33,998 2,212
year
Notes payable 38,524 57,516 54,016
Accounts payable 73,499 69,064 36,370
Accounts payable gas trading 28,476 42,874 -
Taxes accrued 24,785 24,295 17,304
Interest accrued 18,365 17,918 15,886
Deferred income taxes 2,965 3,164 4,397
Other 12,275 13,703 12,439
Total current liabilities 204,918 262,532 142,624
DEFERRED CREDITS:
Regulatory liabilities associated
with deferred investment 69,396 70,196 71,283
tax credits
Deferred income taxes 422,196 423,736 411,890
Regulatory liabilities 28,075 34,072 35,028
associated with income taxes
Regulatory liabilities - other 4,161 509 616
Other 70,572 96,114 95,938
Total deferred credits 594,400 624,627 614,755
COMMITMENTS AND CONTINGENT
LIABILITIES
TOTAL $2,451,620 $2,451,816 $2,328,738
The accompanying notes are an integral part of these statements.
IDACORP, Inc.
Consolidated Statements of Capitalization
December 31,
1998 % 1997 % 1996 %
(Thousands of Dollars)
COMMON STOCK EQUITY
Common stock $ 451,564 $ 452,519 $ 452,486
Retained earnings 278,607 259,299 242,088
Accumulated other comprehensive 226 - -
Total common stock equity 730,397 44 711,818 45 694,574 44
PREFERRED STOCK OF IDAHO POWER
COMPANY
4% preferred stock 15,968 16,697 16,975
7.68% Series, serial preferred
stock 15,000 15,000 15,000
7.07% Series, serial preferred
stock 25,000 25,000 25,000
Auction rate preferred stock 50,000 50,000 50,000
Total preferred stock 105,968 7 106,697 7 106,975 7
LONG-TERM DEBT OF IDAHO POWER
COMPANY
First mortgage bonds:
5.33 % Series due 1998 - 30,000 30,000
8.65 % Series due 2000 80,000 80,000 80,000
6.93 % Series due 2001 30,000 30,000 30,000
6.85 % Series due 2002 27,000 27,000 27,000
6.40 % Series due 2003 80,000 80,000 80,000
8 % Series due 2004 50,000 50,000 50,000
5.83 % Series due 2005 60,000 - -
Maturing 2021 through 2031
with rates ranging
from 7.5% to 9.52% 230,000 230,000 230,000
Total first mortgage bonds 557,000 527,000 527,000
Amount due within one year - (30,000) -
Net first mortgage bonds 557,000 497,000 527,000
Pollution control revenue
bonds:
7 1/4 % Series due 2008 4,360 4,360 4,360
8.30 % Series 1984 due 2014 49,800 49,800 49,800
6.05 % Series 1996A due 2026 68,100 68,100 68,100
Variable Rate Series 1996B
due 2026 24,200 24,200 24,200
Variable Rate Series 1996C
due 2026 24,000 24,000 24,000
Total pollution control
revenue bonds 170,460 170,460 170,460
REA notes 1,489 1,561 1,632
Amount due within one year (74) (72) (71)
Net REA notes 1,415 1,489 1,561
American Falls bond guarantee 20,130 20,355 20,560
Milner Dam note guarantee 11,700 11,700 11,700
Debt related to investments in
affordable housing with
rates ranging from 6.97% to
8.59% due 1999 to 2009 62,103 46,385 33,401
Amount due within one year (5,955) (3,926) (2,141)
Net affordable housing debt 56,148 42,459 31,260
Unamortized premium/discount - Net (1,539) (1,637) (1,731)
Net Idaho Power Company debt 815,314 741,826 760,810
OTHER SUBSIDIARY DEBT 623 4,316 9,000
Total long-term debt 815,937 49 746,142 48 769,810 49
TOTAL CAPITALIZATION $1,652,302 100 $1,564,657 100 $1,571,359 100
The accompanying notes are an integral part of these statements.
IDACORP, Inc.
Consolidated Statements of Cash Flows
Year Ended December 31,
1998 1997 1996
(Thousands of Dollars)
OPERATING ACTIVITIES:
Net income $ 89,176 $ 87,098 $ 83,155
Adjustments to reconcile net
income to net cash:
Depreciation and amortization 87,143 80,485 78,228
Deferred taxes and investment
tax credits (10,182) 5,978 7,967
Accrued PCA costs 21,658 (7,038) (6,768)
Change in:
Accounts receivable and 4,883 (69,589) 5,482
prepayments
Accrued unbilled revenue (1,298) (5,603) (2,684)
Materials and supplies and (925) (57) 2,730
fuel stock
Accounts payable (9,963) 75,731 (4,277)
Taxes accrued 489 6,991 1,895
Other current assets and
liabilities (825) 3,296 673
Other - net (10,269) (5,562) 551
Net cash provided by operating
activities 169,887 171,730 166,952
INVESTING ACTIVITIES:
Additions to utility plant (89,184) (95,633) (93,645)
Investments in affordable
housing projects (19,139) (17,021) (18,281)
Other investments - - (20,153)
Other - net 3,206 (1,302) 825
Net cash used in investing
activities (105,117) (113,956) (131,254)
FINANCING ACTIVITIES:
Proceeds from issuance of:
First mortgage bonds 60,000 - 57,000
Pollution control revenue - - 116,300
bonds
Long-term debt related to
affordable housing projects 15,718 12,984 17,924
Other long-term debt - - 9,000
Retirement of:
Subsidiary long-term debt (4,316) (4,700) -
First mortgage bonds (30,000) - (20,249)
Pollution control revenue - - (116,300)
bonds
Preferred stock of Idaho
Power Company - - (26,530)
Dividends on common stock (69,868) (69,887) (69,924)
Increase (decrease) in short-
term borrowings (18,992) 3,500 996
Other - net (1,350) (694) (4,455)
Net cash used in financing
activities (48,808) (58,797) (36,238)
Net increase (decrease) in cash
and cash equivalents 15,962 (1,023) (540)
Cash and cash equivalents
beginning of period 6,905 7,928 8,468
Cash and cash equivalents at end
of period $ 22,867 $ 6,905 $ 7,928
SUPPLEMENTAL DISCLOSURE OF CASH
FLOW INFORMATION:
Cash paid during the period
for:
Income taxes $ 55,527 $ 41,786 $ 45,050
Interest (net of amount 53,806 $ 53,319 $ 53,273
capitalized)
The accompanying notes are an integral part of these statements.
IDACORP, Inc.
Consolidated Statements of Retained Earnings
Year Ended December 31,
1998 1997 1996
(Thousands of Dollars)
RETAINED EARNINGS, BEGINNING OF YEAR $259,299 $242,088 $229,827
NET INCOME 89,176 87,098 83,155
Total 348,475 329,186 312,982
COMMON STOCK DIVIDENDS (69,868) (69,887) (69,924)
PREFERRED STOCK REDEMPTION - Idaho
Power Company - - (970)
RETAINED EARNINGS, END OF YEAR $278,607 $259,299 $242,088
The accompanying notes are an integral part of these statements.
Consolidated Statements of Comprehensive Income
Year Ended December 31,
1998 1997 1996
(Thousands of Dollars)
NET INCOME $ 89,176 $ 87,098 $ 83,155
OTHER COMPREHENSIVE INCOME:
Unrealized gains on securities
(net of tax of $2,185) 3,385 - -
Minimum pension liability
adjustment (net of tax of $2,054) (3,159) - -
TOTAL COMPREHENSIVE INCOME $ 89,402 $ 87,098 $ 83,155
The accompanying notes are an integral part of these statements
IDACORP, Inc.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Nature of Business
IDACORP, Inc. (the Company) is a holding company formed in 1998 as
the parent to Idaho Power Company (IPC), Ida-West Energy Company,
and IDACORP Energy Solutions Inc. IPC's outstanding common stock
was converted on a share-for-share basis into common stock of the
Company. However, IPC's preferred shares and debt securities
outstanding were unaffected and remain with IPC.
IPC, a public utility, represents over 90% of the total assets of
the Company and is its principal operating subsidiary. IPC is
regulated by the Federal Energy Regulatory Commission (FERC) and
the state commissions of Idaho, Oregon, Nevada and Wyoming, is
engaged in the generation, transmission, distribution, sale and
purchase of electric energy, and has approximately 374,000 retail
customers and 1,669 employees.
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
Principles of Consolidation
The consolidated financial statements include the accounts of the
Company and its wholly owned or controlled subsidiaries. All
significant intercompany transactions and balances have been
eliminated in consolidation. Investments in business entities in
which the Company and its subsidiaries do not have control, but
have the ability to exercise significant influence over operating
and financial policies, are accounted for using the equity method.
System of Accounts
The accounting records of IPC conform to the Uniform System of
Accounts prescribed by the FERC and adopted by the public utility
commissions of Idaho, Oregon, Nevada and Wyoming.
Electric Plant
The cost of additions to electric plant in service represents the
original cost of contracted services, direct labor and material,
allowance for funds used during construction and indirect charges
for engineering, supervision and similar overhead items.
Maintenance and repairs of property and replacements and renewals
of items determined to be less than units of property are charged
to operations. For property replaced or renewed the original cost
plus removal cost less salvage is charged to accumulated provision
for depreciation while the cost of related replacements and
renewals is added to electric plant.
Allowance For Funds Used During Construction (AFDC)
The allowance, a non-cash item, represents the composite interest
costs of debt, shown as a reduction to interest charges, and a
return on equity funds, shown as an addition to other income, used
to finance construction. While cash is not realized currently from
such allowance, it is realized under the rate making process over
the service life of the related property through increased revenues
resulting from higher rate base and higher depreciation expense.
Based on the uniform formula adopted by the FERC, IPC's weighted-
average monthly AFDC rates for 1998, 1997 and 1996 were 6.0
percent, 5.8 percent and 6.1 percent, respectively.
Revenues
In order to match revenues with associated expenses, IPC accrues
unbilled revenues for electric services delivered to customers but
not yet billed at month-end.
Under terms and conditions of a regulatory settlement with the
Idaho Public Utilities Commission (IPUC), if IPC's actual earnings
in a given year exceed an 11.75 percent return on year-end common
equity, it will set aside 50 percent of the excess for the benefit
of IPC's Idaho retail customers. In 1998, 1997 and 1996,
approximately $5.4 million, $7.6 million and $4.9 million of
revenues were set aside for the benefit of Idaho retail customers.
Power Cost Adjustment
IPC has a Power Cost Adjustment (PCA) mechanism that provides for
annual adjustments to the rates charged to Idaho retail customers.
These adjustments are based on forecasts of net power supply costs,
and take effect annually on May 16. The difference between the
actual costs incurred and the forecasted costs are deferred, with
interest, and trued-up in the next annual rate adjustment.
Depreciation
All electric plant is depreciated using the straight-line method.
Annual depreciation provisions as a percent of average depreciable
electric plant in service approximated 2.87 percent in 1998, 2.93
percent in 1997 and 2.89 percent in 1996 and are considered
adequate to amortize the original cost over the estimated service
lives of the properties.
Income Taxes
The Company follows the liability method of computing deferred
taxes on all temporary differences between the book and tax basis
of assets and liabilities and adjusts deferred tax assets and
liabilities for enacted changes in tax laws or rates. Consistent
with orders and directives of the IPUC the regulatory authority
having principal jurisdiction, IPC's deferred income taxes
(commonly referred to as normalized accounting) are provided for
the difference between income tax depreciation and straight-line
depreciation on coal-fired generation facilities and properties
acquired after 1980. On other facilities, deferred income taxes
are provided for the difference between accelerated income tax
depreciation and straight-line depreciation using tax guideline
lives on assets acquired prior to 1981. Deferred income taxes are
not provided for those income tax timing differences where the
prescribed regulatory accounting methods do not provide for current
recovery in rates. Regulated enterprises are required to recognize
such adjustments as regulatory assets or liabilities if it is
probable that such amounts will be recovered from or returned to
customers in future rates (see Note 2).
The state of Idaho allows a three-percent investment tax credit
(ITC) upon certain qualifying plant additions. ITC earned on
regulated assets are deferred and amortized to income over the
estimated service lives of the related properties. Credits earned
on non-regulated assets or investments are recognized in the year
earned.
In 1995, IPC received an accounting order from the IPUC that
allowed for accelerated amortization of up to $30.0 million of
regulatory liabilities associated with deferred ITC to non-
operating income. The Internal Revenue Service and the Idaho State
Tax Commission have both approved the application. Acceleration of
ITC amortization is to be utilized until the actual return on year-
end common equity is 11.5 percent. No accelerated ITC was
recognized in 1998, 1997 or 1996.
Cash and Cash Equivalents
For purposes of reporting cash flows, cash and cash equivalents
include cash on hand and highly liquid temporary investments with
maturity dates at date of acquisition of three months or less. The
Company has changed the presentation of operating activities in its
consolidated statements of cash flows from the direct to the
indirect method. The years 1997 and 1996 have been reclassified to
conform to the new presentation.
Management Estimates
The preparation of financial statements in conformity with
generally accepted accounting principles requires management to
make estimates and assumptions that affect the reported amounts of
assets and liabilities and the disclosure of contingent assets and
liabilities at the date of the financial statements and the
reported amounts of revenues and expenses during the reporting
period. Actual results could differ from those estimates.
Regulation of Utility Operations
Electric utilities have historically been recognized as natural
monopolies and have operated in a highly regulated environment in
which they have an obligation to provide electric service to their
customers in return for an exclusive franchise within their service
territory with an opportunity to earn a regulated rate of return.
This regulatory environment is changing. The generation sector has
experienced competition from non-utility power and market
producers, and the FERC is requiring utilities, including IPC, to
provide wholesale open-access transmission service to others and
may order electric utilities to enlarge their transmission systems
to facilitate transmission services.
Some state regulatory authorities are in the process of changing
utility regulations in response to federal and state statutory
changes and evolving competitive markets. These statutory and
conforming regulations may result in increased wholesale and retail
competition. Due to IPC's low cost structure, it is well
positioned to compete in the evolving utility market place.
However, the Company is unable to predict what financial impact or
effect the adoption of any such legislation would have on IPC's
operations.
IPC follows Statement of Financial Accounting Standards (SFAS) No.
71, "Accounting for the Effects of Certain Types of Regulation,"
and its financial statements reflect the effects of the different
rate making principles followed by the various jurisdictions
regulating IPC. Pursuant to SFAS No. 71 IPC capitalizes, as
deferred regulatory assets, incurred costs that are expected to be
recovered in future utility rates. IPC also records as deferred
regulatory liabilities the current recovery in utility rates of
costs that are expected to be paid in the future.
The following is a breakdown of IPC's regulatory assets and
liabilities for the years 1998, 1997 and 1996:
1998 1997 1996
Assets Liabilities Assets Liabilities Assets Liabilities
(Millions of Dollars)
Income taxes $204.4 $ 28.1 $201.7 $ 34.1 $201.1 $ 35.0
Conservation 43.3 - 42.4 - 40.3 -
Employee benefits 5.6 - 6.5 - 7.4 -
PCA deferral and (5.2) - 16.6 - 9.6 -
amortization
Other 18.3 4.1 24.7 0.5 32.2 0.6
Deferred investment - 69.4 - 70.2 - 71.3
tax credits
Total $266.4 $101.6 $291.9 $104.8 $290.6 $106.9
At December 31, 1998, IPC had $14.1 million of regulatory assets
that were not earning a return on investment excluding the $204.4
million that relates to income taxes.
In the event that recovery of costs through rates becomes unlikely
or uncertain, SFAS No. 71 would no longer apply. If the Company
were to discontinue application of SFAS No. 71 for some or all of
IPC's operations, then these items may represent stranded
investments. If the Company is not allowed recovery of these
investments, it would be required to write off the applicable
portion of regulatory assets and the financial effects could be
significant.
Derivative Financial Instruments
IPC uses financial instruments such as commodity futures, options
and swaps to hedge against exposure to commodity price risk in the
electricity and natural gas markets. The objective of IPC's
hedging program is to mitigate the risk associated with the
purchase and sale of natural gas and electricity. The accounting
for derivative financial instruments that are used to manage risk
is in accordance with the concepts established in SFAS No. 80,
"Accounting for Futures Contracts," American Institute of Certified
Public Accountants Statement of Position 86-2, "Accounting for
Options," and various Emerging Issues Task Force (EITF)
pronouncements.
Deferral (hedge) accounting is used if certain hedging criteria are
met and is applied only if the derivative reduces the risk of the
underlying hedged item and is designated at inception as a hedge
with respect to the hedged item. Additionally, the derivative must
result in payoffs that are expected to be inversely correlated to
those of the hedged item.
Gains and losses from derivatives that reduce the commodity price
risk related to electricity are recognized as purchased power
expenses when the hedged transaction occurs. Gains and losses from
derivatives that reduce the commodity price risk related to natural
gas are recognized as a component of gas trading activities when
the hedged transaction occurs. Cash flows from derivatives are
recognized in the statement of cash flows and are in the same
category as that of the hedged item.
IPC's policy also allows for the use of financial instruments noted
above for trading purposes in support of Company operations. Gains
or losses on financial instruments that do not qualify for hedge
accounting are recognized in income on a current basis.
The following table shows a summary of IPC's derivative positions
as of December 31, 1998 and 1997. No derivative positions existed
at December 31, 1996.
1998 1997
Gas Electricity Gas Electricity
MMBTU's MWh's MMBTU's MWh's
Futures:
Purchase 21,210,000 286,304 3,560,000 21,344
Sale 18,590,000 370,944 3,510,000 -
Options:
Purchase - 18,400 - -
Sale - 43,200 - -
Swaps 27,568,610 - 15,104 -
Comprehensive Income
The Company adopted SFAS No. 130, "Reporting Comprehensive Income"
effective January 1, 1998. The statement establishes standards for
reporting and displaying comprehensive income and its components in
the Company's financial statements.
Components of the Company's comprehensive income include net
income, the Company's proportionate share of unrealized holding
gains on marketable securities held by an equity investee, and the
changes in additional minimum liability under a deferred
compensation plan for certain senior management employees and
directors.
New Accounting Pronouncements
In June 1998, the Financial Accounting Standards Board (FASB)
issued SFAS No. 133, "Accounting for Derivative Instruments and
Hedging Activities." This statement is effective for all fiscal
quarters of all fiscal years beginning after June 15, 1999, and
establishes accounting and reporting standards for derivative
instruments, including certain derivative instruments embedded in
other contracts, and for hedging activities. The Company is
evaluating the effect of this statement on its financial position
and results of operations.
EITF 98-10, "Accounting for Contracts Involved in Energy Trading
and Risk Management Activities" is issued and effective for
financial statements for fiscal years beginning after December 15,
1998. The Company anticipates the impact of adoption on its
financial position and results of operations will be immaterial.
Other Accounting Policies
Debt discount, expense and premium are being amortized over the
terms of the respective debt issues.
Reclassifications
Certain items previously reported for years prior to 1998 have been
reclassified to conform to the current year's presentation.
2. INCOME TAXES:
IPC has settled Federal and Idaho tax liabilities on all open years
through the 1995 tax year except for amounts related to a
partnership which have been, in management's opinion, adequately
accrued.
A reconciliation between the statutory federal income tax rate and
the effective rate is as follows:
1998 1997 1996
Computed income taxes based
on statutory
federal income tax rate $ 46,832 $ 46,750 $ 47,336
Change in taxes resulting
from:
Investment tax credits (2,934) (2,887) (2,835)
Repair allowance (2,800) (2,800) (2,800)
Settlement of prior years
tax returns (1,965) 23 (16)
Current state income taxes 6,258 3,587 2,823
Depreciation 5,237 5,766 5,945
Affordable housing tax
credits (6,880) (4,519) (1,777)
Preferred dividends of IPC 1,980 1,811 2,613
Other (1,098) (1,259) 803
Total provision for federal
and state income taxes $ 44,630 $ 46,472 $ 52,092
Effective tax rate 33.4 % 34.8 % 38.5 %
The provision for income taxes consists of the following:
1998 1997 1996
Income taxes currently
payable:
Federal $ 45,606 $ 35,038 $ 40,379
State 9,206 5,456 3,746
Total 54,812 40,494 44,125
Income taxes deferred -
Net of amortization:
Federal (8,006) 6,717 6,877
State (1,376) 348 314
Total (9,382) 7,065 7,191
Investment tax credits:
Deferred 2,134 1,800 3,611
Restored (2,934) (2,887) (2,835)
Total (800) (1,087) 776
Total provision for income
taxes $ 44,630 $ 46,472 $ 52,092
The tax effects of significant items comprising the Company's net
deferred tax liability are as follows:
1998 1997 1996
Deferred tax assets:
Regulatory liabilities $ 28,075 $ 34,072 $ 35,028
Advances for construction 10,401 18,665 17,736
Other 20,512 16,536 13,550
Total 58,988 69,273 66,314
Deferred tax liabilities:
Electric plant 247,270 251,938 245,652
Regulatory assets 204,430 201,685 201,093
Investment tax credits 69,396 70,196 71,283
Conservation programs 16,866 14,377 13,720
Other 15,583 28,173 22,136
Total 553,545 566,369 553,884
Net deferred tax $494,557 $497,096 $487,570
liabilities
3. COMMON STOCK:
Changes in shares of IDACORP common stock for 1998, 1997 and 1996
were as follows:
Shares Amount
Balance at December 31, 1995 37,612,351 $452,948
Other - Net (462)
Balance at December 31, 1996 37,612,351 452,486
Other - Net 33
Balance at December 31, 1997 37,612,351 452,519
Other - Net (955)
Balance at December 31, 1998 37,612,351 $451,564
As of December 31, 1998; 2,791,321 of authorized but unissued
shares of IDACORP common stock were reserved for future issuance
under the Company's Dividend Reinvestment and Stock Purchase Plan
and IPC's Employee Savings Plan. In addition, 314,114 shares are
reserved for the Restricted Stock Plan (see Note 9).
The Company has a Shareholder Rights Plan (Plan) designed to ensure
that all shareholders receive fair and equal treatment in the event
of any proposal to acquire control of the Company. Under the Plan,
the Company declared a distribution of one Preferred Share Purchase
Right (Right) for each of the Company's outstanding Common Shares
held on October 1, 1998 or issued thereafter. The Rights are
currently not exercisable and will be exercisable only if a person
or group (Acquiring Person) either acquires ownership of 20 percent
or more of the Company's Voting Stock or commences a tender offer
that would result in ownership of 20 percent or more of such stock.
The Company may redeem all but not less than all of the Rights at a
price of $0.01 per Right or exchange the Rights for cash,
securities (including Common Shares of the Company) or other assets
at any time prior to the close of business on the 10th day after
acquisition by an Acquiring Person of a 20 percent or greater
position.
Additionally, the IDACORP Board created the A Series Preferred
Stock, without Par Value, and reserved 1,200,000 shares for
issuance upon exercise of the Rights.
Following the acquisition of a 20 percent or greater position, each
Right will entitle its holder to purchase for $95 that number of
shares of Common Stock or Preferred Stock having a market value of
$190.
If after the Rights become exercisable, the Company is acquired in
a merger or other business combination, 50 percent or more of its
consolidated assets or earnings power are sold or the Acquiring
Person engages in certain acts of self-dealing, each Right entitles
the holder to purchase for $95, shares of the acquiring company's
common stock having a market value of $190.
Any Rights that are or were held by an Acquiring Person become void
if any of these events occurs. The Rights expire on September 30,
2008.
The Rights themselves do not give any voting or other rights as
shareholders to their holders. The terms of the Rights may be
amended without the approval of any holders of the Rights until an
Acquiring Person obtains a 20 percent or greater position, and then
may be amended as long as the amendment is not adverse to the
interests of the holders of the Rights.
4. PREFERRED STOCK OF IDAHO POWER COMPANY:
The number of shares of IPC preferred stock outstanding at December
31, 1998, 1997 and 1996 were as follows:
Shares Outstanding at
December 31, Call Price
1998 1997 1996 Per Share
Preferred stock:
Cumulative, $100 par value:
4% preferred stock
(authorized
215,000 shares) 159,680 166,972 169,753 $104.00
Serial preferred stock,
7.68% Series (authorized
150,000 shares) 150,000 150,000 150,000 $102.97
Serial preferred stock,
cumulative, without
par value; total of
3,000,000 shares authorized:
7.07% Series, $100 stated
value,(authorized 250,000
shares) (a) 250,000 250,000 250,000 $103.535 to $100.354
shares)(a)
Auction rate preferred
stock, $100,000 stated
value, (authorized 500
shares)(b) 500 500 500 $100,000.00
Total 560,180 567,472 570,253
(a) The preferred stock is not redeemable prior to July 1, 2003.
(b) Dividend rate at December 31, 1998 was 4.02% and ranged
between 4.29% and 3.97% during the year.
During 1998, 1997 and 1996 IPC reacquired and retired 7,292; 2,781;
and 2,060 shares of 4% preferred stock. As of December 31, 1998
the overall effective cost of all outstanding preferred stock was
5.57 percent.
On November 7, 1996, IPC redeemed for $26.4 million, the $25.0
million principal amount of 8.375% Series, serial preferred stock
without par value, ($100 stated value) from proceeds of the
issuance of $27.0 million principal amount of secured medium term
notes, Series B, 6.85%, Due 2002.
5. LONG-TERM DEBT:
The Company currently has a $300.0 million shelf registration
statement that can be used for the issuance of unsecured debt
securities and preferred or common stock. At December 31, 1998,
none had been issued.
The amount of first mortgage bonds issuable by IPC is limited to a
maximum of $900.0 million and by property, earnings and other
provisions of the mortgage and supplemental indentures thereto.
Substantially all of the electric utility plant is subject to the
lien of the indenture.
Pollution Control Revenue Bonds, Series 1984, due December 1, 2014,
are secured by First Mortgage Bonds, Pollution Control Series A,
which were issued by IPC and are held by a Trustee for the benefit
of the bondholders.
IPC currently has a $200.0 million shelf registration statement
with a balance of $83.0 million that remains to be issued. This
can be used for first mortgage bonds (including medium term notes)
or preferred stock.
First mortgage bonds maturing during the five-year period ending
2003 are $0 in 1999, $80.0 million in 2000, $30.0 million in 2001,
$27.0 million in 2002 and $80.0 million in 2003.
On July 29, 1996, IPC issued $30.0 million principal amount of
Secured Medium Term Notes, Series B, 6.93% Series Due 2001. The
net proceeds were used for repayment of commercial paper issued in
connection with IPC's ongoing construction program. On October 2,
1996, $27.0 million principal amount of Secured Medium Term Notes,
Series B, 6.85% Due 2002 were issued with net proceeds from this
sale used to redeem IPC's $25.0 million of 8.375% Series, Serial
Preferred Stock, Without Par Value.
On September 9, 1998, $60.0 million principal amount of Secured
Medium Term Notes, Series B 5.83% Series due 2005 were issued by
IPC. Proceeds from this issuance were used to redeem at maturity,
the $30.0 million First Mortgage Bonds 5.33% Series B due September
1998, with the balance used for repayment of commercial paper
issued in connection with IPC's ongoing business.
On August 29, 1996, tax exempt Pollution Control Revenue Refunding
Bonds were issued by IPC in principal amount of $68.1 million
Series 1996A, $24.2 million Series 1996B and $24.0 million Series
1996C. The proceeds were used to retire the $24.2 million
Pollution Control Revenue Bonds due 2003, $24.0 million Pollution
Control Revenue Bonds due 2007 and the $68.1 million Pollution
Control Revenue Bonds due 2013-2014. At December 31, 1998, 1997
and 1996 the overall effective cost of all outstanding first
mortgage bonds and pollution control revenue bonds was 7.69
percent, 7.84 percent and 7.73 percent, respectively.
At December 31, 1998, IDACORP Financial Services, Inc., a wholly
owned subsidiary of IPC, has $62.1 million of debt with interest
rates ranging from 6.97 percent to 8.59 percent. This debt is
collateralized by investments in affordable housing projects with a
book-value of $65.9 million at December 31, 1998. Principal
amounts maturing during the five-year period ending 2003 are $6.0
million in 1999, $6.5 million in 2000, $6.9 million in 2001, $7.1
million in 2002 and $6.5 million in 2003.
6. FAIR VALUE OF FINANCIAL INSTRUMENTS:
The estimated fair value of the Company's financial instruments has
been determined by the Company using available market information
and appropriate valuation methodologies. The use of different
market assumptions and/or estimation methodologies may have a
material effect on the estimated fair value amounts.
Cash and cash equivalents, customer and other receivables, notes
payable, accounts payable, interest accrued, and taxes accrued are
reported at their carrying value as these are a reasonable estimate
of their fair value. The estimated fair values for long-term debt
and investments are based upon quoted market prices of the same or
similar issues or discounted cash flow analyses as appropriate.
The total estimated fair value of the Company's debt was
approximately $877.4 million in 1998, $801.8 million in 1997 and
$806.8 million for 1996. Included in investments and other
property were financial instruments totaling $14.2 million in 1998,
$16.5 million in 1997 and $18.0 million in 1996. Estimated fair
value of these instruments was $20.3 million in 1998, $19.9 million
in 1997 and $18.7 million in 1996.
7. NOTES PAYABLE:
On December 21, 1998, the Company established a $100.0 million 364-
day credit facility which will expire December 19, 1999, and a
$50.0 million 3-year credit facility which will expire December 21,
2001. Under these facilities the Company pays a facility fee on
the commitment, quarterly in arrears, based on IPC's First Mortgage
Bond Rating. Commercial paper may be issued up to the $150.0
million and are supported by the bank credit facilities.
The Company has no short-term balance outstanding at December 31,
1998.
At December 31, 1998, IPC had regulatory authority to incur up to
$200.0 million of short-term indebtedness. On December 19, 1996,
IPC replaced its committed lines of credit arrangements with a
$120.0 million multi-year revolving credit facility, which will
expire on December 19, 2001. Under this facility IPC pays a
facility fee on the commitment, quarterly in arrears, based on
IPC's First Mortgage Bond rating. Commercial paper may be issued
in an amount not to exceed 25 percent of revenues for the latest
twelve-month period subject to the $200.0 million maximum and are
supported by bank lines of credit of an equal amount.
Balances and interest rates of short-term borrowings for IPC were
as follows:
Year Ended December
31,
1998 1997 1996
(Thousands of Dollars)
Balance at end of year $38,524 $57,516 $54,016
Effective annual interest rate 6.0 % 6.1 % 5.7 %
at end of year
8. COMMITMENTS AND CONTINGENT LIABILITIES:
Commitments under contracts and purchase orders relating to IPC's
program for construction and operation of facilities amounted to
approximately $10.5 million at December 31, 1998. The commitments
are generally revocable by IPC subject to reimbursement of
manufacturers' expenditures incurred and/or other termination
charges.
IPC is currently purchasing energy from 66 on-line cogeneration and
small power production facilities with contracts ranging from 1 to
32 years. Under these contracts IPC is required to purchase all of
the output from these facilities. During the fiscal year ended
December 31, 1998, IPC purchased 907,096 MWh at a cost of $55.0
million.
The Company is party to various legal claims, actions, and
complaints, certain of which involve material amounts. Although
unable to predict with certainty whether or not it will ultimately
be successful in these legal proceedings, or, if not, what the
impact might be, based upon the advice of legal counsel, management
presently believes that disposition of these matters will not have
a material adverse effect on the Company's financial position,
results of operation or cash flow.
9. BENEFIT PLANS:
Pension Plans
IPC sponsors a noncontributory defined benefit pension plan for all
employees who work 1,000 hours or more during a calendar year. The
benefits under the plan are based on years of service and the
employee's final average earnings. IPC's policy is to fund with an
independent corporate trustee at least the minimum required under
the Employee Retirement Income Security Act of 1974 but not more
than the maximum amount deductible for income tax purposes. IPC
was not required to contribute to the plan during 1998, 1997 and
1996. The trustee invests the plan's assets primarily in listed
stocks (both U.S. and foreign), fixed income securities and
investment grade real estate.
IPC has a nonqualified, deferred compensation plan for certain
senior management employees and directors that provides for
supplemental retirement and death benefit payments to the
participant and his or her family. IPC financed this plan by
purchasing life insurance policies for which it is the beneficiary
and through investments in marketable securities held by a trustee.
The cash value of the policies and investments exceed the projected
benefit obligation of the plan but do not qualify as plan assets in
the actuarial computation of the funded status.
The following table shows the components of net periodic pension
cost for these plans (in thousands of dollars):
Pension Plan Deferred Compensation Plan
1998 1997 1996 1998 1997 1996
Service cost $ 7,133 $ 6,152 $ 6,273 $ 572 $ 515 $ 596
Interest cost 15,458 14,445 13,647 1,747 1,731 1,679
Expected return on assets (22,724) (20,248) (18,145) - - -
Recognized net actuarial
(gain) loss (111) - - 255 222 248
Amortization of prior
service cost 424 424 424 (332) (346) (339)
Amortization of
transition asset (263) (263) (263) 613 613 613
Net periodic pension
cost $ (83) $ 510 $ 1,936 $ 2,855 $ 2,735 $ 2,797
The following table sets forth the funded status of these plans (in
thousands of dollars):
Pension Plan Deferred Compensation Plan
1998 1997 1996 1998 1997 1996
Change in projected
benefit obligation:
Beginning of year
benefit obligation $224,073 $202,049 $193,133 $ 25,067 $ 24,122 $ 23,692
Service cost 7,133 6,152 6,273 572 516 596
Interest cost 15,458 14,445 13,647 1,747 1,731 1,679
Actuarial loss (gain) 14,139 12,763 (564) 1,297 806 189
Benefits paid (11,774) (11,336) (10,440) (2,049) (2,303) (1,958)
Plan amendments 4,700 - - 395 195 (76)
End of year benefit 253,729 224,073 202,049 27,029 25,067 24,122
obligation
Change plan assets:
Plan assets at fair
value at beginning
of year 256,893 230,478 204,760 - - -
Actual return on plan
assets 44,961 37,751 30,234 - - -
Employer contributions - - 5,924 - - -
Benefit payments (11,774) (11,336) (10,440) - - -
Plan assets at fair
value at end of year 290,080 256,893 230,478 - - -
Funded status 36,351 32,820 28,429 (27,029) (25,067) (24,122)
Unrecognized actuarial
loss/(gain) (33,722) (25,734) (20,994) 6,612 5,569 4,985
Unrecognized prior
service cost 9,370 5,093 5,517 (1,166) (1,893) (2,434)
Unrecognized net
transition liability (1,704) (1,967) (2,230) 3,988 4,601 5,214
(Accrued)/ Prepaid cost
(net amount recognized) 10,295 20,212 10,722 (17,595) (16,790) (16,357)
Additional minimum
liability - - - (8,036) (7,867) (6,402)
Minimum liability $ 10,295 $ 10,212 $ 10,722 $(25,631) $(24,657) $(22,759)
Amount recognized in
the statement of
financial position
consist of:
Prepaid (accrued)
pension cost $ 10,295 $ 10,212 $ 10,722 $(25,631) $(24,657) $(22,759)
Intangible asset - - - 2,822 7,867 6,402
Accumulated other
comprehensive income - - - 5,214 - -
Net amount recognized $ 10,295 $ 10,212 $ 10,722 $(17,595) $(16,790) $(16,357)
The following table sets forth the assumptions used at the end of
each year for all IPC-sponsored pension and postretirement benefit
plans:
Pension Benefits Postretirement Benefits
1998 1997 1996 1998 1997 1996
Discount rate 6.75 % 7.10 % 7.35 % 6.75 % 7.35 % 7.60 %
Expected long-term rate of
return on assets 9.0 9.0 9.0 9.0 9.0 9.0
Annual salary increases 4.5 4.5 4.5 - - -
Restricted Stock Plan
IPC implemented a restricted stock plan in 1995 as an equity-based
long-term incentive plan for certain key employees. Each grant has
a three-year restricted period and final award amounts depend on
the attainment of a cumulative earnings per share performance goal.
At December 31, 1998, there were 314,114 shares of common stock
reserved for the plan.
Restricted stock awards are compensatory awards and IPC accrues
compensation expense (which is charged to operations) based upon
the market value of the granted shares. For the years 1998, 1997
and 1996, total compensation accrued for the plan was $567,000,
$539,000 and, $184,000 respectively.
IPC applies APB Opinion 25 and related interpretations in
accounting for this plan. Had compensation cost for IPC's grants
of restricted stock been determined consistent with the optional
fair value based method provisions of SFAS No. 123, "Account for
Stock-Based Compensation," IPC's net income and earnings per share
of common stock for 1998, 1997 and 1996 would not be significantly
different from such amounts as reported.
The following table summarizes restricted stock activity for the
years 1998, 1997 and 1996:
1998 1997 1996
Shares outstanding -
beginning of year, 38,365 18,140 9,120
Shares granted 21,361 20,225 9,740
Shares forfeited (4,063) - (720)
Shares issued (12,600) - -
Shares outstanding - end of
year 43,063 38,365 18,140
Weighted average fair value
of current year
stock grants on grant date $ 37.00 $ 31.25 $ 30.25
Savings Plan
IPC sponsors an Employee Savings Plan under which employees may
contribute a percentage of their base salary. IPC matches the
first two percent of salary contributed by the employee and 50
percent of the next four percent of salary contributed by the
employee. All amounts are invested by a trustee in any or all of
seven investment options. Matching contributions amounted to $3.0
million in 1998, $2.4 million in 1997 and, $2.3 million in 1996.
Postretirement Benefits
IPC maintains a defined benefit postretirement plan (consisting of
health care and life insurance) that covers all employees who were
enrolled in the active group plan at the time of retirement, their
spouses and qualifying dependents.
IPC has a retiree medical benefits funding program which consists
of life insurance policies on active employees for which IPC is the
beneficiary, and a qualified Voluntary Employees Beneficiary
Association (VEBA) Trust. IPC was not required to contribute to
the plan in 1998, 1997 and 1996. The VEBA trust represents plan
assets that are invested in variable life insurance policies, Trust
Owned Life Insurance (TOLI), on active employees. Inside buildup
in the TOLI policies is tax deferred and tax free if the policy
proceeds are paid to the Trust as death benefits. The investment
return assumption reflects an expectation that investment income in
the VEBA will be substantially tax free.
The net periodic postretirement benefit cost was as follows (in
thousands of dollars):
1998 1997 1996
Service cost $ 720 $ 713 $ 794
Interest cost 2,913 3,029 3,172
Expected return on plan assets (1,761) (1,511) (1,410)
Amortization of unrecognized
transition obligation 2,040 2,040 2,040
Amortization of prior service
cost (280) (87) -
Amortization of unrecognized
net gains (220) (240) (57)
Net periodic postretirement
benefit cost $ 3,412 $ 3,944 $ 4,539
The following table sets forth the funded status of this
postretirement health and life insurance benefit plan (in thousands
of dollars):
1998 1997 1996
Change in accumulated benefit
obligation:
Benefit obligation at
beginning of year $43,459 $44,439 $48,928
Service cost 720 713 794
Interest cost 2,913 3,029 3,172
Plan amendments (9,071) (1,214) -
Actuarial loss (gain) 3,483 (1,940) (6,984)
Benefits paid (2,889) (1,568) (1,471)
Benefit obligation at end of
year 38,615 43,459 44,439
Change in plan assets:
Fair value of plan assets at
beginning of year 19,493 17,341 15,920
Actual return on plan assets 4,853 2,152 1,421
Employer (excess)
contributions 2,789 1,553 1,421
Benefits paid (2,789) (1,553) (1,421)
Fair value of plan assets at
end on year 24,346 19,493 17,341
Funded status (14,269) (23,966) (27,098)
Unrecognized prior service cost (9,918) (1,127) -
Unrecognized actuarial
(gain)/loss (7,256) (7,867) (5,526)
Unrecognized transition
obligation 28,560 30,600 32,640
Accrued postretirement benefit
obligations included with othe
long-term liabilities $(2,883) $(2,360) $ 16
liabilities
The assumed health care cost trend rate used to measure the
expected cost of benefits covered by the plan is 6.75%. A one-
percentage point change in the assumed health care cost trend rate
would have the following effect (in thousands of dollars):
1-Percentage- 1-Percentage-
Point increase Point decrease
Effect on total of service and
interest cost components $ 279 $ (259)
Effect on accumulated
postretirement benefit obligation 2,286 (2,159)
Postemployment Benefits
The Company provides certain benefits to former or inactive
employees, their beneficiaries, and covered dependents after
employment but before retirement. These benefits include salary
continuation, health care and life insurance for those employees
found to be disabled under our disability plans, and health care
for surviving spouses and dependents. The Company accrues a
liability for such benefits. In accordance with an IPUC order, the
portion of the liability attributable to regulated activities in
Idaho as of December 31, 1993, was deferred as a regulatory asset,
and is being amortized over ten years. The following table
summarizes postemployment benefits amounts included in the
Company's consolidated balance sheet (in thousands of dollars):
1998 1997 1996
Included with regulatory
assets - other $2,260 $2,632 $3,003
Included with other
deferred credits (3,372) (3,093) (4,128)
10. ELECTRIC PLANT IN SERVICE AND JOINTLY-OWNED PROJECTS:
The following table sets out the major classifications of the
Company's electric plant in service, accumulated provision for
depreciation and annual depreciation provisions as a percent of
average depreciable balance for the years 1998, 1997 and 1996 (in
thousands of dollars):
1998 1997 1996
Balance Avg Rate Balancc Avg Rate Balance Avg Rate
Production $1,344,526 2.60% $1,333,768 2.60% $1,323,090 2.58%
Transmission 389,011 2.30 378,190 2.28 371,123 2.29
Distribution 736,527 3.15 715,091 3.38 688,232 3.35
General and Other 189,377 5.45 178,648 5.39 155,120 5.23
Total In Service 2,659,441 2.87 2,605,697 2.93 2,537,565 2.89
Less accumulated
provision for
depreciation 1,009,387 942,400 886,885
In Service - Net $1,650,054 $1,663,297 $1,650,680
IPC is involved in the ownership and operation of three jointly-
owned generating facilities. The Consolidated Statements of Income
include IPC's proportionate share of direct operation and
maintenance expenses applicable to the projects.
Each facility and extent of IPC participation as of December 31,
1998 are as follows:
Company Ownership
Accumulated
Electric Plant Provision
Name of Plant Location In Service for Depreciation % MW
(Thousands of Dollars)
Jim Bridger Rock Springs, $383,139 $190,139 33 708
Units 1-4 WY
Boardman Boardman, OR 61,486 32,071 10 53
Valmy Units 1 Winnemucca, NV 299,763 130,118 50 261
and 2
IPC's wholly owned subsidiary, IERCo, is a joint venturer in
Bridger Coal Company, which operates the mine supplying coal for
the Jim Bridger steam generation plant. Coal purchased by IPC from
the joint venture amounted to $46.2 million in 1998, $40.7 million
in 1997 and, $35.0 million in 1996.
IPC has contracts to purchase the energy from five PURPA Qualified
Facilities that are 50 percent owned by Ida-West Energy Company, a
wholly owned subsidiary of the Company. Power purchased from these
facilities amounted to $8.7 million in 1998, $9.8 million in 1997
and $9.0 million in 1996.
11. INDUSTRY SEGMENT INFORMATION:
In June 1997 the FASB issued SFAS No. 131, "Disclosures about
Segments of an Enterprise and Related Information." This Statement
requires financial and descriptive disclosure for fiscal years
beginning after December 15, 1997, about certain operating segments
of an enterprise as well as enterprise-wide disclosure of certain
product and geographic information.
The Company is predominantly a one operating segment company with
the regulated electric operations of IPC being the most dominant
segment. Other subsidiaries of the Company, subsidiaries of IPC
and non-utility operating segments of IPC do not individually
constitute more than 10% of enterprise revenues, income or assets,
nor in aggregate do they comprise more than 25% of enterprise
revenues, income or assets.
IPC's primary business is the generation, transmission,
distribution, purchase and sale of electricity. IPC also began
natural gas trading activities in May 1997 and reports this
activity in Other Income in the Consolidated Statements of Income.
The following table summarizes the segment information for IPC
Utility with a reconciliation to total enterprise information:
IPC Total
Utility Other Enterprise
(Thousands of Dollars)
1998
Revenues $1,121,976 $ - $1,121,976
Income from
operations 191,221 - 191,221
Other income 5,909 2,111 8,020
Interest expense 56,646 3,131 59,777
Income before income
taxes 140,484 (6,678) 133,806
Income taxes 51,447 (6,817) 44,630
Net income 89,037 139 89,176
Total assets 2,310,322 141,298 2,451,620
Expenditures for
long-lived assets 91,803 19,205 111,008
1997
Revenues $ 748,503 $ - $ 748,503
Income from
operations 184,749 - 184,749
Other income 3,894 10,361 14,255
Interest expense 57,653 2,605 60,258
Income before income
taxes 130,990 2,580 133,570
Income taxes 49,125 (2,653) 46,472
Net income 81,865 5,233 87,098
Total assets 2,338,524 113,292 2,451,816
Expenditures for
long-lived assets 98,219 17,457 115,676
1996
Revenues $ 578,445 $ - $ 578,445
Income from
operations 187,171 - 187,171
Other income 2,759 9,775 12,534
Interest expense 56,110 885 56,995
Income before income
taxes 133,821 1,426 135,247
Income taxes 51,386 706 52,092
Net income 82,435 720 83,155
Total assets 2,245,880 82,858 2,328,738
Expenditures for
long-lived assets 97,484 34,595 132,079
Substantially all of the Company's revenue comes from the sale of
electricity and related services, predominately in the United
States. The Company sells natural gas, solar electric products and
systems, control systems integration services for substations and
semiconductor manufacturing, and miscellaneous other services
however, these revenues are not significant.
INDEPENDENT AUDITORS' REPORT
To The Board of Directors and Shareowners of
IDACORP, Inc.
Boise, Idaho
We have audited the accompanying consolidated balance sheets and
statements of capitalization of IDACORP, Inc. and its subsidiaries
as of December 31, 1998, 1997 and 1996, and the related
consolidated statements of income, cash flows, retained earnings
and comprehensive income for the years then ended. Our audits also
included the consolidated financial statement schedule listed in
the Index at Item 8. These financial statements and financial
statement schedule are the responsibility of the Company's
management. Our responsibility is to express an opinion on the
financial statements and financial statement schedule based on our
audits.
We conducted our audits in accordance with generally accepted
auditing standards. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the
financial statements are free of material misstatement. An audit
includes examining, on a test basis, evidence supporting the
amounts and disclosures in the financial statements. An audit also
includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits
provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present
fairly, in all material respects, the financial position of
IDACORP, Inc. and subsidiaries at December 31, 1998, 1997 and 1996,
and the results of their operations and their cash flows for the
years then ended in conformity with generally accepted accounting
principles. Also, in our opinion, such financial statement
schedule, when considered in relation to the basic consolidated
financial statements taken as a whole, presents fairly in all
material respects the information set forth therein.
DELOITTE & TOUCHE LLP
Boise, Idaho
January 29, 1999
Idaho Power Company
Consolidated Statements of Income
Year Ended December 31,
1998 1997 1996
(Thousands of Dollars)
REVENUES:
General business $ 514,856 $ 480,458 $ 484,145
Off system sales 579,984 243,874 70,222
Other revenues 27,136 24,171 24,078
Total revenues 1,121,976 748,503 578,445
EXPENSES:
Operation:
Purchased power 540,200 219,200 69,038
Fuel expense 86,237 71,271 63,334
Power cost adjustment 21,866 (6,032) (6,859)
Other 145,374 137,458 132,667
Maintenance 41,872 48,722 42,731
Depreciation 74,481 71,973 69,705
Taxes other than income taxes 20,725 21,162 20,658
Total expenses 930,755 563,754 391,274
INCOME FROM OPERATIONS 191,221 184,749 187,171
OTHER INCOME:
Allowance for equity funds used
during construction 300 34 46
Gas trading activities - Net (3,208) (1,181) -
Other - Net 12,364 15,402 12,488
Total other income 9,456 14,255 12,534
INTEREST CHARGES
Interest on long-term debt 52,270 53,215 52,165
Other interest 8,323 7,546 5,183
Allowance for borrowed funds
used during construction (900) (503) (353)
Total interest charges 59,693 60,258 56,995
INCOME BEFORE INCOME TAXES 140,984 138,746 142,710
INCOME TAXES 45,065 46,472 52,092
NET INCOME 95,919 92,274 90,618
Dividends on preferred stock 5,658 5,176 7,463
EARNINGS ON COMMON STOCK $ 90,261 $ 87,098 $ 83,155
The accompanying notes are an integral part of these statements.
Idaho Power Company
Consolidated Balance Sheets
Assets
December 31,
1998 1997 1996
(Thousands of Dollars)
ELECTRIC PLANT:
In service (at original cost) $2,659,441 $2,605,697 $2,537,565
Accumulated provision for
depreciation (1,009,387) (942,400) (886,885)
In service - Net 1,650,054 1,663,297 1,650,680
Construction work in progress 58,904 51,892 42,178
Held for future use 1,738 1,738 1,773
Electric plant - Net 1,710,696 1,716,927 1,694,631
INVESTMENTS AND OTHER PROPERTY 105,600 97,065 69,903
CURRENT ASSETS:
Cash and cash equivalents 20,029 6,905 7,928
Receivables:
Customer 81,227 63,076 34,962
Allowance for uncollectible
accounts (1,397) (1,397) (1,394)
Gas trading 21,426 42,128 -
Notes 467 4,613 5,104
Employee notes 4,510 4,757 4,486
Other (includes $3,164 from
related parties in 1998) 8,502 8,854 8,489
Accrued unbilled revenues 34,610 33,312 27,709
Materials and supplies (at
average cost) 30,143 29,156 24,639
Fuel stock (at average cost) 7,096 7,172 11,631
Prepayments 16,011 15,381 16,165
Regulatory assets associated
with income taxes 2,965 3,164 4,397
Total current assets 225,589 217,121 144,116
DEFERRED DEBITS:
American Falls and Milner water
rights 31,830 32,055 32,260
Company-owned life insurance 35,149 51,915 57,291
Regulatory assets associated
with income taxes 201,465 198,521 196,696
Regulatory assets - other 62,013 90,239 89,507
Other 49,448 47,973 44,334
Total deferred debits 379,905 420,703 420,088
TOTAL $2,421,790 $2,451,816 $2,328,738
The accompanying notes are an integral part of these statements.
Idaho Power Company
Consolidated Balance Sheets
Capitalization and Liabilities
December 31,
1998 1997 1996
(Thousands of Dollars)
CAPITALIZATION:
Common stock equity:
Common stock, $2.50 par value
(50,000,000 shares authorized;
37,612,351 shares outstanding) $ 94,031 $ 94,031 $ 94,031
Premium on capital stock 362,156 362,328 362,297
Capital stock expense (3,823) (3,840) (3,842)
Retained earnings 252,137 259,299 242,088
Accumulated other
comprehensive income 226 - -
Total common stock equity 704,727 711,818 694,574
Preferred stock 105,968 106,697 106,975
Long-term debt 815,937 746,142 769,810
Total capitalization 1,626,632 1,564,657 1,571,359
CURRENT LIABILITIES:
Long-term debt due within one
year 6,029 33,998 2,212
Notes payable 38,508 57,516 54,016
Accounts payable 72,660 69,064 36,370
Accounts payable gas trading 28,476 42,874 -
Taxes accrued 25,164 24,295 17,304
Interest accrued 18,364 17,918 15,886
Deferred income taxes 2,965 3,164 4,397
Other 12,117 13,703 12,439
Total current liabilities 204,283 262,532 142,624
DEFERRED CREDITS:
Regulatory liabilities associated
with deferred investment
tax credits 69,396 70,196 71,283
Deferred income taxes 420,268 423,736 411,890
Regulatory liabilities
associated with income taxes 28,075 34,072 35,028
Regulatory liabilities - other 4,161 509 616
Other 68,975 96,114 95,938
Total deferred credits 590,875 624,627 614,755
COMMITMENTS AND CONTINGENT
LIABILITIES
TOTAL $2,421,790 $2,451,816 $2,328,738
The accompanying notes are an integral part of these statements.
Idaho Power Company
Consolidated Statements of Capitalization
December 31,
1998 % 1997 % 1996 %
(Thousands of Dollars)
COMMON STOCK EQUITY
Common stock $ 94,031 $ 94,031 $ 94,031
Premium on capital stock 362,156 362,328 362,297
Capital stock expense (3,823) (3,840) (3,842)
Retained earnings 252,137 259,299 242,088
Accumulated other comprehensive
income 226 - -
Total common stock equity 704,727 43 711,818 45 694,574 44
PREFERRED STOCK
4% preferred stock 15,968 16,697 16,975
7.68% Series, serial preferred
stock 15,000 15,000 15,000
7.07% Series, serial preferred
stock 25,000 25,000 25,000
Auction rate preferred stock 50,000 50,000 50,000
Total preferred stock 105,968 7 106,697 7 106,975 7
LONG-TERM DEBT
First mortgage bonds:
5.33 % Series due 1998 - 30,000 30,000
8.65 % Series due 2000 80,000 80,000 80,000
6.93 % Series due 2001 30,000 30,000 30,000
6.85 % Series due 2002 27,000 27,000 27,000
6.40 % Series due 2003 80,000 80,000 80,000
8 % Series due 2004 50,000 50,000 50,000
5.83 % Series due 2005 60,000 - -
Maturing 2021 through 2031
with rates ranging
from 7.5% to 9.52% 230,000 230,000 230,000
Total first mortgage bonds 557,000 527,000 527,000
Amount due within one year - (30,000) -
Net first mortgage bonds 557,000 497,000 527,000
Pollution control revenue
bonds:
7 1/4% Series due 2008 4,360 4,360 4,360
8.30 % Series 1984 due 2014 49,800 49,800 49,800
6.05 % Series 1996A due 2026 68,100 68,100 68,100
Variable Rate Series 1996B
due 2026 24,200 24,200 24,200
Variable Rate Series 1996C
due 2026 24,000 24,000 24,000
Total pollution control
revenue bonds 170,460 170,460 170,460
REA notes 1,489 1,561 1,632
Amount due within one year (74) (72) (71)
Net REA notes 1,415 1,489 1,561
American Falls bond guarantee 20,130 20,355 20,560
Milner Dam note guarantee 11,700 11,700 11,700
Debt related to investments in
affordable housing with rates
ranging from 6.97% to
8.59% due 1999 to 2009 62,103 46,385 33,401
Amount due within one year (5,955) (3,926) (2,141)
Net affordable housing debt 56,148 42,459 31,260
Other subsidiary debt 623 4,316 9,000
Unamortized premium/discount - (1,539) (1,637) (1,731)
Net
Total long-term debt 815,937 50 746,142 48 769,810 49
TOTAL CAPITALIZATION $1,626,632 100 $1,564,657 100 $1,571,359 100
The accompanying notes are an integral part of these statements.
Idaho Power Company
Consolidated Statements of Cash Flows
Year Ended December 31,
1998 1997 1996
(Thousands of Dollars)
OPERATING ACTIVITIES:
Net income $ 95,919 $ 92,274 $ 90,618
Adjustments to reconcile net
income to net cash:
Depreciation and amortization 87,044 80,485 78,228
Deferred taxes and investment
tax credits (10,127) 5,978 7,967
Accrued PCA costs 21,658 (7,038) (6,768)
Change in:
Accounts receivable and
prepayments 1,985 (69,589) 5,482
Accrued unbilled revenue (1,298) (5,603) (2,684)
Materials and supplies and
fuel stock (911) (57) 2,730
Accounts payable (10,658) 75,731 (4,277)
Taxes accrued 1,312 6,991 1,895
Other current assets and
liabilities (857) 3,296 673
Other - net (10,340) (5,562) 551
Net cash provided by operating
activities 173,727 176,906 174,415
INVESTING ACTIVITIES:
Additions to utility plant (89,644) (95,633) (93,645)
Investments in affordable
housing projects (19,139) (17,021) (18,281)
Other investments - - (20,153)
Other - net 867 (1,302) 825
Net cash used in investing
activities (107,916) (113,956) (131,254)
FINANCING ACTIVITIES:
Proceeds from issuance of:
First mortgage bonds 60,000 - 57,000
Pollution control revenue - - 116,300
bonds
Long-term debt related to
affordable housing projects 15,718 12,984 17,924
Other long-term debt - - 9,000
Retirement of:
Subsidiary long-term debt (3,316) (4,700) -
First mortgage bonds (30,000) - (20,249)
Pollution control revenue - - (116,300)
bonds
Preferred stock - - (26,530)
Dividends on common stock (69,889) (69,887) (69,924)
Dividends on preferred stock (5,658) (5,176) (7,463)
Increase (decrease) in short- (18,992) 3,500 996
term borrowings
Other - net (550) (694) (4,455)
Net cash used in financing
activities (52,687) (63,973) (43,701)
Net increase (decrease) in cash 13,124 (1,023) (540)
and cash equivalents
Cash and cash equivalents 6,905 7,928 8,468
beginning of period
Cash and cash equivalents at end
of period $ 20,029 $ 6,905 $ 7,928
SUPPLEMENTAL DISCLOSURE OF CASH
FLOW INFORMATION:
Cash paid during the period
for:
Income taxes $ 55,527 $ 41,786 $ 45,050
Interest (net of amount
capitalized) $ 53,806 $ 53,319 $ 53,273
Net assets of affiliates
transferred to parent $ 27,534 - -
The accompanying notes are an integral part of these statements.
Idaho Power Company
Consolidated Statements of Retained Earnings
Year Ended December 31,
1998 1997 1996
(Thousands of Dollars)
RETAINED EARNINGS, BEGINNING OF YEAR $259,299 $242,088 $229,827
NET INCOME 95,919 92,274 90,618
Total 355,218 334,362 320,445
DIVIDENDS
Common stock ($1.86 per share) (69,889) (69,887) (69,924)
Preferred stock (5,658) (5,176) (7,463)
TRANSFER TO IDACORP, INC. (27,534) - -
PREFERRED STOCK REDEMPTION - - (970)
RETAINED EARNINGS, END OF YEAR $252,137 $259,299 $242,088
The accompanying notes are an integral part of these statements.
Consolidated Statements of Comprehensive Income
Year Ended December 31,
1998 1997 1996
(Thousands of Dollars)
NET INCOME $ 95,919 $ 92,274 $ 90,618
OTHER COMPREHENSIVE INCOME:
Unrealized gains on securities
(net of tax of $2,185) 3,385 - -
Minimum pension liability
adjustment (net of tax of $2,054) (3,159) - -
TOTAL COMPREHENSIVE INCOME $ 96,145 $ 92,274 $ 90,618
The accompanying notes are an integral part of these statements.
Idaho Power Company
Notes to the Consolidated Financial Statements
On October 1, 1998, IDACORP, Inc. (IDACORP) became the parent of
Idaho Power Company and its subsidiaries (IPC). At that time,
IPC's ownership interests in two subsidiaries were transferred to
IDACORP at book value. IPC's financial statements include the
following amounts attributable to the transferred subsidiaries for
the periods prior to October 1, 1998:
As of/Year Ended December 31,
1998 1997 1996
(Thousands of Dollars)
Total assets $ - $ 31,369 $ 33,258
Net assets - 23,311 21,255
Net income 3,024 2,057 1,249
Except as modified below, the Notes to the Consolidated Financial
Statements of IDACORP beginning on page 45 of this 1998 Annual
Report on Form 10-K are incorporated herein by reference insofar as
they relate to IPC.
Note 1 - Summary of Significant Accounting Policies
Note 3 - Common Stock
Note 4 - Preferred Stock of Idaho Power Company
Note 5 - Long-Term Debt
Note 7 - Notes Payable
Note 8 - Commitments and Contingent Liabilities
Note 9 - Employee Benefit Plans
Note 10 - Electric Plant in Service and Jointly Owned Projects
Note 2 - Income Taxes
IPC has settled Federal and Idaho tax liabilities on all open years
through the 1995 tax year except for amounts related to a
partnership which have been, in management's opinion, adequately
accrued.
A reconciliation between the statutory federal income tax rate and
the effective rate is as follows:
1998 1997 1996
Computed income taxes based on
statutory federal
income tax rate $ 49,344 $ 48,561 $ 49,949
Change in taxes resulting
from:
Investment tax credits (2,934) (2,887) (2,835)
Repair allowance (2,800) (2,800) (2,800)
Settlement of prior years tax (1,965) 23 (16)
returns
Current state income taxes 6,309 3,587 2,823
Depreciation 5,237 5,766 5,945
Affordable housing tax (6,880) (4,519) (1,777)
credits
Other (1,246) (1,259) 803
Total provision for federal $ 45,065 $ 46,472 $ 52,092
and state income taxes
Effective tax rate 32.0 % 33.5 % 36.5 %
The provision for income taxes consists of the following:
1998 1997 1996
Income taxes currently payable:
Federal $ 45,909 $ 35,038 $ 40,379
State 9,283 5,456 3,746
Total 55,192 40,494 44,125
Income taxes deferred - Net of
amortization:
Federal (8,006) 6,717 6,877
State (1,321) 348 314
Total (9,327) 7,065 7,191
Investment tax credits:
Deferred 2,134 1,800 3,611
Restored (2,934) (2,887) (2,835)
Total (800) (1,087) 776
Total provision for income
taxes $ 45,065 $ 46,472 $ 52,092
The tax effects of significant items comprising the Company's net
deferred tax liability are as follows:
1998 1997 1996
Deferred tax assets:
Regulatory liabilities $ 28,075 $ 34,072 $ 35,028
Advances for construction 10,401 18,665 17,736
Other 20,457 16,536 13,550
Total 58,933 69,273 66,314
Deferred tax liabilities:
Electric plant 247,270 251,938 245,652
Regulatory assets 204,430 201,685 201,093
Investment tax credits 69,396 70,196 71,283
Conservation programs 16,866 14,377 13,720
Other 13,600 28,173 22,136
Total 551,562 566,369 553,884
Net deferred tax liabilities $492,629 $497,096 $487,570
Note 6 - Fair Value of Financial Instruments
The estimated fair value of IPC's financial instruments has been
determined by using available market information and appropriate
valuation methodologies. The use of different market assumptions
and/or estimation methodologies may have a material effect on the
estimated fair value amounts.
Cash and cash equivalents, customer and other receivables, notes
payable, accounts payable, interest accrued, and taxes accrued are
reported at their carrying value as these are a reasonable estimate
of their fair value. The estimated fair values for long-term debt
and investments are based upon quoted market prices of the same or
similar issues or discounted cash flow analyses as appropriate.
The total estimated fair value of IPC's debt was approximately
$877.4 million in 1998, $801.8 million in 1997 and $806.8 million
for 1996. Included in investments and other property were
financial instruments totaling $16.5 million in 1997 and $18.0
million in 1996. Estimated fair value of these instruments was
$19.9 million in 1997 and $18.7 million in 1996. These investments
were included in the net assets transferred to IDACORP during 1998.
Note 11 - Industry Segment Information
In June 1997 the FASB issued SFAS No. 131, "Disclosures about
Segments of an Enterprise and Related Information." This Statement
requires financial and descriptive disclosure for fiscal years
beginning after December 15, 1997, about certain operating segments
of an enterprise as well as enterprise-wide disclosure of certain
product and geographic information.
IPC is predominantly a one operating segment company with its
regulated electric operations being the most dominant segment.
Other subsidiaries and non-utility operating segments do not
individually constitute more than 10% of enterprise revenues,
income or assets, nor in aggregate do they comprise more than 25%
of enterprise revenues, income or assets.
IPC's primary business is the generation, transmission,
distribution, purchase and sale of electricity. IPC also began
natural gas trading activities in May 1997 and reports this
activity in Other Income in the Consolidated Statements of Income.
The following table summarizes the segment information for the
regulated electric operations with a reconciliation to total
enterprise information:
Regulated
Electric Total
Operations Other Enterprise
(Thousands of Dollars)
1998
Revenues $1,121,976 $ - $1,121,976
Income from operations 191,221 - 191,221
Other income 5,909 3,547 9,456
Interest expense 56,646 3,047 59,693
Income before income 140,484 500 140,984
taxes
Income taxes 51,447 (6,382) 45,065
Net income 89,037 6,882 95,919
Total assets 2,312,919 108,871 2,421,790
Expenditures for long- 91,803 19,197 111,000
lived assets
1997
Revenues $ 748,503 $ - $ 748,503
Income from operations 184,749 - 184,749
Other income 3,894 10,361 14,255
Interest expense 57,653 2,605 60,258
Income before income 130,990 2,580 133,570
taxes
Income taxes 49,125 (2,653) 46,472
Net income 81,865 5,233 87,098
Total assets 2,338,524 113,292 2,451,816
Expenditures for long- 98,219 17,457 115,676
lived assets
1996
Revenues $ 578,445 $ - $ 578,445
Income from operations 187,171 - 187,171
Other income 2,759 9,775 12,534
Interest expense 56,110 885 56,995
Income before income 133,821 1,426 135,247
taxes
Income taxes 51,386 706 52,092
Net income 82,435 720 83,155
Total assets 2,245,880 82,858 2,328,738
Expenditures for long- 97,484 34,595 132,079
lived assets
Substantially all revenues come from the sale of electricity and
related services, predominately in the United States. IPC sells
natural gas, solar electric products and systems, control systems
integration services for substations and semiconductor
manufacturing, and miscellaneous other services however, these
revenues are not significant.
INDEPENDENT AUDITORS' REPORT
To The Board of Directors and Shareowners of
Idaho Power Company
Boise, Idaho
We have audited the accompanying consolidated balance sheets and
statements of capitalization of Idaho Power Company and its
subsidiaries as of December 31, 1998, 1997 and 1996, and the
related consolidated statements of income, cash flows, retained
earnings, and comprehensive income for the years then ended. Our
audits also included the consolidated financial statement schedule
listed in the Index at Item 8. These financial statements and
financial statement schedule are the responsibility of the
Company's management. Our responsibility is to express an opinion
on the financial statements and financial statement schedule based
on our audits.
We conducted our audits in accordance with generally accepted
auditing standards. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the
financial statements are free of material misstatement. An audit
includes examining, on a test basis, evidence supporting the
amounts and disclosures in the financial statements. An audit also
includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits
provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present
fairly, in all material respects, the financial position of Idaho
Power Company and subsidiaries at December 31, 1998, 1997 and 1996,
and the results of their operations and their cash flows for the
years then ended in conformity with generally accepted accounting
principles. Also, in our opinion, such financial statement
schedule, when considered in relation to the basic consolidated
financial statements taken as a whole, presents fairly in all
material respects the information set forth therein.
DELOITTE & TOUCHE LLP
Boise, Idaho
January 29, 1999 SUPPLEMENTAL FINANCIAL INFORMATION, UNAUDITED
QUARTERLY FINANCIAL DATA:
The following unaudited information is presented for each quarter
of 1998, 1997 and 1996 (in thousands of dollars, except for per
share amounts). In the opinion of the Companies, all adjustments
necessary for a fair statement of such amounts for such periods
have been included. The results of operations for the interim
periods are not necessarily indicative of the results to be
expected for the full year. Accordingly, earnings information for
any three-month period should not be considered as a basis for
estimating operating results for a full fiscal year. Amounts are
based upon quarterly statements and the sum of the quarters may not
equal the annual amount reported.
IDACORP, INC. Quarter Ended
March 31 June 30 September 30 December 31
1998
Revenues $238,170 $221,622 $392,378 $269,805
Income from operations 56,555 42,783 47,459 44,424
Income taxes 13,125 9,213 12,392 9,900
Net income 28,050 20,351 22,305 18,468
Earnings per share of 0.75 0.54 0.59 0.49
common stock
1997
Revenues 155,447 166,975 217,174 208,908
Income from operations 59,073 41,778 43,877 40,025
Income taxes 16,361 9,126 10,715 10,270
Net income 28,986 19,377 19,719 19,018
Earnings per share of 0.77 0.52 0.52 0.51
common stock
1996
Revenues 146,629 140,384 149,652 141,781
Income from operations 58,489 46,741 41,780 40,161
Income taxes 17,466 12,828 11,597 10,201
Net income 28,259 21,106 17,197 16,593
Earnings per share of 0.75 0.56 0.45 0.44
common stock
Idaho Power Company Quarter Ended
March 31 June 30 September 30 December 31
30 31
1998
Revenues $238,170 $221,622 $392,378 $269,805
Income from operations 56,555 42,783 47,459 44,424
Income taxes 13,125 9,213 12,392 10,335
Net income 29,455 21,768 23,715 20,979
Dividends on preferred 1,405 1,417 1,410 1,426
stock
Earnings on common stock 28,050 20,351 22,305 19,553
1997
Revenues 155,447 166,975 217,174 208,908
Income from operations 59,073 41,778 43,877 40,025
Income taxes 16,361 9,126 10,715 10,270
Net income 30,380 20,042 21,141 20,715
Dividends on preferred 1,394 665 1,422 1,696
stock
Earnings on common stock 28,966 19,377 19,719 19,019
1996
Revenues 146,629 140,384 149,652 141,781
Income from operations 58,489 46,741 41,780 40,161
Income taxes 17,466 12,828 11,597 10,201
Net income 30,211 23,033 19,151 18,225
Dividends on preferred 1,952 1,927 1,954 1,632
stock
Earnings on common stock 28,259 21,106 17,197 16,593
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE
None
PART III
Part III has been omitted because the registrants will file a
definitive proxy statement pursuant to Regulation 14A, which
involves the election of Directors, with the Commission within 120
days after the close of the fiscal year portions of which are
hereby incorporated by reference (except for information with
respect to executive officers which is set forth in Part I hereof).
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON
FORM 8-K
(a) Please refer to Item 8, "Financial Statements and
Supplementary Data" for a complete listing of all consolidated
financial statements and financial statement schedules.
(b) Reports on SEC Form 8-K. The following reports on Form 8-K
were filed for the three months ended December 31, 1998:
Items Reported Date of Report
Filed by
Item 5, Other Events September 15, 1998 IDACORP,
Inc.
Item 7, Exhibits
Item 5, Other Events October 1, 1998
IDACORP, Inc.
Item 7, Financial Statements
and IPC
and Exhibits
(c) Exhibits.
*Previously Filed and Incorporated Herein by Reference
Exhibit File Number As Exhibit
*2 333-48031 2 Agreement and Plan of Exchange
between IDACORP, Inc., and IPC dated
as of February 2, 1998.
*3(a) 33-00440 4(a)(xiii) Restated Articles of Incorporation
of IPC as filed with the Secretary
of State of Idaho on June 30, 1989.
*3(a)(i) 33-65720 4(a)(ii) Statement of Resolution Establishing
Terms of Flexible Auction Series A,
Serial Preferred Stock, Without Par
Value (cumulative stated value of
$100,000 per share) of IPC, as filed
with the Secretary of State of Idaho
on November 5, 1991.
*3(a)(ii) 33-65720 4(a)(iii) Statement of Resolution Establishing
Terms of 7.07% Serial Preferred
Stock, Without Par Value (cumulative
stated value of $100 per share) of
IPC, as filed with the Secretary of
State of Idaho on June 30, 1993.
*3(b) 33-41166 4(b) Waiver resolution to Restated
Articles of Incorporation of IPC
adopted by Shareholders on May 1,
1991.
*3(c) 33-00440 4(a)(xiv) By-laws of IPC amended on June 30,
1989, and presently in effect.
*3(d) 33-56071 3(d) Articles of Share Exchange of
IDACORP, Inc. as filed with the
Secretary of State of Idaho on
September 29, 1998.
*3(e) 333-64737 3.1 Articles of Incorporation of
IDACORP, Inc.
*3(f) 333-64737 3.2 Articles of Amendment to Articles of
Incorporation of IDACORP, Inc. as
filed with the Secretary of State of
Idaho on March 9, 1998.
*3(g) 333-00139 3(b) Articles of Amendment to Restated
Articles of Incorporation of
IDACORP, Inc. creating A Series
Preferred Stock, without par value
as filed with the Secretary of State
of Idaho on September 17, 1998.
*3(h) 333-48031 3(c) Amended Bylaws of IDACORP, Inc. as
of September 10, 1998.
*4(a)(i) 2-3413 B-2 Mortgage and Deed of Trust, dated as
of October 1, 1937, between IPC and
Bankers Trust Company and
R. G. Page, as Trustees.
*4(a)(ii) IPC Supplemental Indentures to
Mortgage and Deed of Trust:
Number Dated
1-MD B-2-a First July 1, 1939
2-5395 7-a-3 Second November 15, 1943
2-7237 7-a-4 Third February 1, 1947
2-7502 7-a-5 Fourth May 1, 1948
2-8398 7-a-6 Fifth November 1, 1949
2-8973 7-a-7 Sixth October 1, 1951
2-12941 2-C-8 Seventh January 1, 1957
2-13688 4-J Eighth July 15, 1957
2-13689 4-K Ninth November 15, 1957
2-14245 4-L Tenth April 1, 1958
2-14366 2-L Eleventh October 15, 1958
2-14935 4-N Twelfth May 15, 1959
2-18976 4-O Thirteenth November 15, 1960
2-18977 4-Q Fourteenth November 1, 1961
2-22988 4-B-16 Fifteenth September 15, 1964
2-24578 4-B-17 Sixteenth April 1, 1966
2-25479 4-B-18 Seventeenth October 1, 1966
2-45260 2(c) Eighteenth September 1, 1972
2-49854 2(c) Nineteenth January 15, 1974
2-51722 2(c)(i) Twentieth August 1, 1974
2-51722 2(c)(ii) Twenty-first October 15, 1974
2-57374 2(c) Twenty-second November 15, 1976
2-62035 2(c) Twenty-third August 15, 1978
33-34222 4(d)(iii) Twenty-fourth September 1, 1979
33-34222 4(d)(iv) Twenty-fifth November 1, 1981
33-34222 4(d)(v) Twenty-sixth May 1, 198
33-34222 4(d)(vi) Twenty-seventh May 1, 1986
33-00440 4(c)(iv) Twenty-eighth June 30, 1989
33-34222 4(d)(vii) Twenty-ninth January 1, 1990
33-65720 4(d)(iii) Thirtieth January 1, 1991
33-65720 4(d)(iv) Thirty-first August 15, 1991
33-65720 4(d)(v) Thirty-second March 15, 1992
33-65720 4(d)(vi) Thirty-third April 16, 1993
1-3198 4 Thirty-fourth December 1, 1993
Form 8-K
Dated
12/17/93
*4(b) Instruments relating to IPC American
Falls bond guarantee. (see Exhibit
10(c)).
*4(c) 33-65720 4(f) Agreement of IPC to furnish certain
debt instruments.
*4(d) 33-00440 2(a)(iii) Agreement and Plan of Merger dated
March 10, 1989, between Idaho Power
Company, a Maine Corporation, and
Idaho Power Migrating Corporation.
*4(e) 33-65720 4(e) Rights Agreement dated January 11,
1990, between IPC and First Chicago
Trust Company of New York, as Rights
Agent (The Bank of New York,
successor Rights Agent).
*4(e)(i) 1-3198 4(e)(i) Amendment, dated as of January 30,
Form 10-K 1998, related to agreement filed as
for 1997 Exhibit 4(e).
*4(f) Form 8-K 4 Rights Agreement, dated as of
dated September 10, 1998, between IDACORP,
September 15, Inc. and the Bank of New York as
1998 Rights Agent.
*10(a) 2-49584 5(b) Agreements, dated September 22,
1969, between IPC and Pacific
Power & Light Company relating to
the operation, construction and
ownership of the Jim Bridger
Project.
*10(a)(i) 2-51762 5(c) Amendment, dated February 1, 1974,
relating to operation agreement
filed as Exhibit 10(a).
*10(b) 2-49584 5(c) Agreement, dated as of October 11,
1973, between IPC and Pacific
Power & Light Company.
*10(c) 33-65720 10(c) Guaranty Agreement, dated March 1,
1990, between IPC and West One Bank,
as Trustee, relating to $21,425,000
American Falls Replacement Dam Bonds
of the American Falls Reservoir
District, Idaho.
*10(d) 2-62034 5(r) Guaranty Agreement, dated as of
August 30, 1974, between IPC and
Pacific Power & Light Company.
*10(e) 2-56513 5(i) Letter Agreement, dated January 23,
1976, between IPC and Portland
General Electric Company.
*10(e)(i) 2-62034 5(s) Agreement for Construction,
Ownership and Operation of the
Number One Boardman Station on Carty
Reservoir, dated as of October 15,
1976, between Portland General
Electric Company and IPC.
*10(e)(ii) 2-62034 5(t) Amendment, dated September 30, 1977,
relating to agreement filed as
Exhibit 10(e).
*10(e)(iii) 2-62034 5(u) Amendment, dated October 31, 1977,
relating to agreement filed as
Exhibit 10(e).
*10(e)(iv) 2-62034 5(v) Amendment, dated January 23, 1978,
relating to agreement filed as
Exhibit 10(e).
*10(e)(v) 2-62034 5(w) Amendment, dated February 15, 1978,
relating to agreement filed as
Exhibit 10(e).
*10(e)(vi) 2-68574 5(x) Amendment, dated September 1, 1979,
relating to agreement filed as
Exhibit 10(e).
*10(f) 2-68574 5(z) Participation Agreement, dated
September 1, 1979, relating to the
sale and leaseback of coal handling
facilities at the Number One
Boardman Station on Carty Reservoir.
*10(g) 2-64910 5(y) Agreements for the Operation,
Construction and Ownership of the
North Valmy Power Plant Project,
dated December 12, 1978, between
Sierra Pacific Power Company and
IPC.
*10(h)(i)1 1-3198 10(n)(i) The Revised Security Plan for Senior
Form 10-K Management Employees - a non-
for 1994 qualified, deferred compensation
plan effective August 1, 1996.
*10(h)(ii)1 1-3198 10(n)(ii) The Executive Annual Incentive Plan
Form 10-K for senior management employees of
for 1994 IPC effective January 1, 1995.
*10(h)(iii)1 1-3198 10(n)(iii) The 1994 Restricted Stock Plan for
Form 10-K officers and key executives of
for 1994 IDACORP, Inc. and IPC effective July
1, 1994.
10(h)(iv)1 The Revised Security Plan for Board
of Directors - a non-qualified,
deferred compensation plan effective
August 1, 1996, revised March 2,
1999.
*10(i) 33-65720 10(h) Framework Agreement, dated October
1, 1984, between the State of Idaho
and IPC relating to IPC's Swan Falls
and Snake River water rights.
*10(i)(i) 33-65720 10(h)(i) Agreement, dated October 25, 1984,
between the State of Idaho and IPC
relating to the agreement filed as
Exhibit 10(i).
*10(i)(ii) 33-65720 10(h)(ii) Contract to Implement, dated October
25, 1984, between the State of Idaho
and IPC relating to the agreement
filed as Exhibit 10(i).
*10(j) 33-65720 10(m) Agreement Regarding the Ownership,
Construction, Operation and
Maintenance of the Milner
Hydroelectric Project (FERC No.
2899), dated January 22, 1990,
between IPC and the Twin Falls Canal
Company and the Northside Canal
Company Limited.
*10(j)(i) 33-65720 10(m)(i) Guaranty Agreement, dated February
10, 1992, between IPC and New York
Life Insurance Company, as Note
Purchaser, relating to $11,700,000
Guaranteed Notes due 2017 of Milner
Dam Inc.
*10(k) 1-3198 10(y) Executive Employment Agreement dated
Form 10-K November 20, 1996 between IPC and
for 1997 Richard R. Riazzi.
12 Statement Re: Computation of Ratio
of Earnings to Fixed Charges.
(IDACORP, Inc.)
12(a) Statement Re: Computation of
Supplemental Ratio of Earnings to
Fixed Charges. (IDACORP, Inc.)
12(b) Statement Re: Computation of Ratio
of Earnings to Combined Fixed
Charges and Preferred Dividend
Requirements. (IDACORP, Inc.)
12(c) Statement Re: Computation of
Supplemental Ratio of Earnings to
Combined Fixed Charges and Preferred
Dividend Requirements. (IDACORP,
Inc.)
12(d) Statement Re: Computation of Ratio
of Earnings to Fixed Charges. (IPC)
12(e) Statement Re: Computation of
Supplemental Ratio of Earnings to
Fixed Charges. (IPC)
12(f) Statement Re: Computation of Ratio
of Earnings to Combined Fixed
Charges and Preferred Dividend
Requirements. (IPC)
12(g) Statement Re: Computation of
Supplemental Ratio of Earnings to
Combined Fixed Charges and Preferred
Dividend Requirements. (IPC)
21 Subsidiaries of IDACORP, Inc. and
IPC.
23 Independent Auditors' Consent.
27(a) Financial Data Schedule for IDACORP,
Inc.
27(b) Financial Data Schedule for IPC.
IDACORP, Inc.
SCHEDULE II - CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
Years Ended December 31, 1998, 1997 and 1996
Column A Column B Column C Column D Column E
Additions
Charged
Balance At Charged (Credited) Balance At
Beginning to to Other Deductions (1) End
Classification of Period Income Accounts Of Period
(Thousands of Dollars)
1998:
Reserves Deducted From
Applicable Assets:
Reserve for
uncollectible
accounts $1,397 $ - $ 3,299(2) $3,299 $1,397
Other Reserves:
Rate refunds $8,740 $4,188 $ - $7,572 $5,356
Injuries and
damages reserve $1,500 $ - $ - $ - $1,500
Miscellaneous
operating reserves $8,388 $ 512 $ - $1,993 $6,907
1997:
Reserves Deducted From
Applicable Assets:
Reserve for
uncollectible
accounts $1,394 $ - $3,384(2) $3,381 $1,397
Other Reserves:
Rate refunds $4,873 $8,740 $ - $4,873 $8,740
Injuries and
damages reserve $1,500 $ - $ - $ - $1,500
Miscellaneous
operating reserves $1,774 $ 592 $7,245 $1,223 $8,388
1996:
Reserves Deducted
From
Applicable Assets:
Reserve for
uncollectible
accounts $1,397 $ - $3,003(2) $3,006 $1,394
Other Reserves:
Rate refunds $ - $4,873 $ - $ - $4,873
Injuries and
damages reserve $1,500 $ - $ - $ - $1,500
Miscellaneous
operating reserves $1,143 $ 681 $ - $ 50 $1,774
Notes: (1) Represents deductions from the reserves for purposes
for which the reserves were created.
(2) Represents collections of accounts previously written
off.
IDAHO POWER COMPANY
SCHEDULE II - CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
Years Ended December 31, 1998, 1997 and 1996
Amounts for Idaho Power Company are same as the above Schedule II
for IDACORP, Inc.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, the Registrant has duly caused
this report to be signed on its behalf by the undersigned,
thereunto duly authorized.
IDACORP, Inc.
(Registrant)
March 11, 1999 By: /s/Joseph W. Marshall
Joseph W. Marshall
Chairman of the Board and
Chief Executive Officer and
Director
Pursuant to the requirements of the Securities Exchange Act of
1934, this report is signed below by the following persons on
behalf of the Registrant and in the capacities and on the dates
indicated.
By /s/Joseph W. Marshall Chairman of the Board and March 11,
: 1999
Joseph W. Marshall Chief Executive Officer
and Director
By /s/Jan B. Packwood President and Chief "
: Operating
Jan B. Packwood Officer and Director
By /s/J. LaMont Keen Vice President, Chief "
: Financial
J. LaMont Keen Officer and Treasurer
(Principal Financial and
Accounting Officer)
By /s/Rotchford L. Barker By /s/Evelyn Loveless "
: :
Rotchford L. Barker Evelyn Loveless
Director Director
By /s/Robert D. Bolinder By /s/Jon H. Miller "
: :
Robert D. Bolinder Jon H. Miller
Director Director
By /s/Roger L. Breezley By /s/Peter S. O'Neill "
: :
Roger L. Breezley Peter S. O'Neill
Director Director
By /s/John B. Carley By /s/Phil Soulen "
: :
John B. Carley Phil Soulen
Director Director
By /s/Peter T. Johnson By /s/Robert A. Tinstman "
: :
Peter T. Johnson Robert A. Tinstman
Director Director
By /s/Jack K. Lemley "
:
Jack K. Lemley
Director
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, the Registrant has duly caused
this report to be signed on its behalf by the undersigned,
thereunto duly authorized.
IDAHO POWER COMPANY.
(Registrant)
March 11, 1999 By: /s/Joseph W. Marshall
Joseph W. Marshall
Chairman of the Board and
Chief Executive Officer and
Director
Pursuant to the requirements of the Securities Exchange Act of
1934, this report is signed below by the following persons on
behalf of the Registrant and in the capacities and on the dates
indicated.
By /s/Joseph W. Marshall Chairman of the Board and March 11,
: 1999
Joseph W. Marshall Chief Executive Officer
and Director
By /s/Jan B. Packwood President and Chief "
: Operating
Jan B. Packwood Officer and Director
By /s/J. LaMont Keen Vice President, Chief "
: Financial
J. LaMont Keen Officer and Treasurer
(Principal Financial and
Accounting Officer)
By /s/Rotchford L. Barker By /s/Evelyn Loveless "
: :
Rotchford L. Barker Evelyn Loveless
Director Director
By /s/Robert D. Bolinder By /s/Jon H. Miller "
: :
Robert D. Bolinder Jon H. Miller
Director Director
By /s/Roger L. Breezley By /s/Peter S. O'Neill "
: :
Roger L. Breezley Peter S. O'Neill
Director Director
By /s/John B. Carley By /s/Phil Soulen "
: :
John B. Carley Phil Soulen
Director Director
By /s/Peter T. Johnson By /s/Robert A. Tinstman "
: :
Peter T. Johnson Robert A. Tinstman
Director Director
By /s/Jack K. Lemley : "
Jack K. Lemley
Director
EXHIBIT INDEX
Exhibit Page
Number Number
10(h)(iv) The Revised Security Plan for 81
Board of Directors - a non-
qualified, deferred
compensation plan effective
August 1, 1996, revised March
2, 1999.
12 Statements Re: Computation of 103
Ratio of Earnings to Fixed
Charges. (IDACORP, Inc.)
12(a) Statements Re: Computation of 104
Supplemental Ratio of
Earnings to Fixed Charges.
(IDACORP, Inc.)
12(b) Statements Re: Computation of 105
Ratio of Earnings to Combined
Fixed Charges and Preferred
Dividend Requirements.
(IDACORP, Inc.)
12(c) Statements Re: Computation of 106
Supplemental Ratio of
Earnings to Combined Fixed
Charges and Preferred
Dividend Requirements.
(IDACORP, Inc.)
12(d) Statements Re: Computation of 107
Ratio of Earnings to Fixed
Charges. (IPC)
12(e) Statements Re: Computation of 108
Supplemental Ratio of
Earnings to Fixed Charges.
(IPC)
12(f) Statements Re: Computation of 109
Ratio of Earnings to Combined
Fixed Charges and Preferred
Dividend Requirements. (IPC)
12(g) Statements Re: Computation of 110
Supplemental Ratio of
Earnings to Combined Fixed
Charges and Preferred
Dividend Requirements. (IPC)
21 Subsidiaries of IDACORP, Inc. 111
and IPC
23 Independent Auditors' 112
Consent.
27(a) Financial Data Schedule for 113
IDACORP, Inc.
27(b) Financial Data Schedule for 114
IPC
EXHIBIT 21
SUBSIDIARIES OF REGISTRANTS
IDACORP, Inc:
1. Idaho Power Company (incorporated in Idaho)
2. Ida-West Energy Company (incorporated in Idaho)
3. IDACORP Energy Solutions Co. (incorporated in Nevada)
4. IDACORP Energy Services Co. (incorporated in Nevada)
5. IDACORP Energy Solutions L.P. (a Delaware limited partnership)
Idaho Power Company
1. Idaho Energy Resources Company (incorporated in Wyoming)
2. IDACORP Financial Services, Inc. (incorporated in Idaho)
3. Stellar Dynamics Inc. (incorporated in Idaho)
4. Idaho Power Resources Corporation (incorporated in Idaho)
5. Applied Power Corporation (incorporated in Washington)
6. Idaho Power Diversified Enterprises Co. (incorporated in
Idaho)
7. Pathnet/Idaho Power Equipment, LLC (a Delaware Limited
Liability Company)
EXHIBIT 23
INDEPENDENT AUDITORS' CONSENT
We consent to the incorporation by reference in Idaho Power
Company's Registration Statement No. 33-51215 on Form S-3
and IDACORP, Inc.'s Registration Statement Nos. 33-56071
and 333-65157 on Form S-8 and Registration Statement Nos.
333-00139 and 333-64737 on Form S-3 of our reports dated
January 29, 1999 on IDACORP, Inc. and Idaho Power Company,
appearing in this Annual Report on Form 10-K of IDACORP,
Inc. and Idaho Power Company for the year ended December
31, 1998.
DELOITTE & TOUCHE LLP
Boise, Idaho
March 19, 1999
_______________________________
1 Compensatory plan
1
1 Compensatory plan
1
Exhibit
10(h)(iv)
IDAHO POWER COMPANY
SECURITY PLAN FOR BOARD OF DIRECTORS
Amended and Restated
Effective August 1, 1996
Revised March 8, 1999
TABLE OF CONTENTS
ARTICLE I
PURPOSE; EFFECTIVE DATE 1
1.1 Purpose 1
ARTICLE II
DEFINITIONS 1
2.1 Actuarial Equivalent 1
2.2 Administrative Committee 2
2.3 Beneficiary 2
2.4 Board 2
2.5 Change in Control 2
2.6 Change in Control Period 4
2.7 Company 4
2.8 Compensation Committee 4
2.9 Contract of Participation 4
2.10 Employer 4
2.11 Participant 4
2.12 Plan Anniversary Date 4
2.13 Plan Year 4
2.14 Supplemental Retirement Benefit 4
2.15 Year of Service 4
ARTICLE III
PARTICIPATION AND VESTING 5
3.1 Participation 5
3.2 Fee Reduction 5
3.3 Vesting 5
ARTICLE IV
SURVIVOR BENEFITS 5
4.1 Death Benefit 5
4.2 Suicide 8
ARTICLE V
RETIREMENT BENEFITS 8
5.1 Benefit 8
5.2 Form of Payment 9
5.3 Commencement of Benefit Payment 9
5.4 Grandfathered Form of Benefit 10
ARTICLE VI
BENEFICIARY DESIGNATION 10
6.1 Beneficiary Designation 10
6.2 Amendments, Marital Status, No Participant Designation 10
6.3 Effect of Payment 11
ARTICLE VII
TERMINATION, SUSPENSION OR AMENDMENT OF PLAN 11
7.1 Termination, Suspension or Amendment of Plan 11
7.2 Change in Control 11
ARTICLE VIII
ADMINISTRATION 12
8.1 Administrative Committee Duties 12
8.2 Indemnity of Administrative Committee 12
ARTICLE IX
CLAIMS PROCEDURE 13
9.1 Claim 13
9.2 Denial of Claim 13
9.3 Review of Claim 13
9.4 Final Decision 14
ARTICLE X
MISCELLANEOUS 14
10.1 Unfunded Plan 14
10.2 Unsecured General Creditor 14
10.3 Trust Fund 15
10.4 Nonassignability 15
10.5 Governing Law 15
10.6 Validity 15
10.7 Notice 16
10.8 Successors 16
10.9 Payment to Guardian 16
10.10 Accelerated Distribution. 16
IDAHO POWER COMPANY
SECURITY PLAN FOR BOARD OF DIRECTORS
AMENDED AND RESTATED AUGUST 1, 1996
ARTICLE I
PURPOSE; EFFECTIVE DATE
1.1 Purpose. The purpose of this restated Security Plan
for Board of Directors (the "Plan") is to define the terms of the
Plan to advance the interests of Idaho Power Company, an Idaho
corporation, and its stockholders by furnishing a variety of
supplemental benefits designed to attract and retain outstanding
individuals as directors of Idaho Power Company, its subsidiaries
and affiliates, and to stimulate the efforts of such directors by
giving suitable recognition to services which will contribute
materially to the success of Idaho Power. The effective date of
this restatement shall be August 1, 1996.
ARTICLE II
DEFINITION
For the purposes of this Plan, the following terms shall
have the meaning indicated, unless the context clearly indicates
otherwise.
2.1 Actuarial Equivalent. "Actuarial Equivalent" shall
mean equivalence in value between two (2) or more forms and/or
times of payment based on a determination by an actuary chosen by
the Company using generally accepted actuarial assumptions,
methods and factors as used in the Retirement Plan of Idaho Power
Company which may be amended from time to time.
For purposes of Section 10.10, Actuarial Equivalent shall be
calculated using the Pension Benefit Guaranty Immediate Rate as
of the month preceding distribution plus 1% and the mortality
table specified in the Retirement Plan of Idaho Power Company
which may be amended from time to time.
2.2 Administrative Committee. "Administrative Committee"
shall mean the committee appointed by the Compensation Committee
pursuant to Section 8.1 hereof to administer the Plan.
2.3 Beneficiary. "Beneficiary" shall mean the person,
persons or entity designated by the Participant or pursuant to
Article VI to receive any benefits payable under the Plan. Each
such designation shall be made in a written instrument filed with
the Administrative Committee and shall become effective only when
received, accepted and acknowledged in writing by the
Administrative Committee or its designee.
2.4 Board. "Board" shall mean the Board of Directors of
the Company.
2.5 Change in Control. "Change in Control" shall mean the
earlier of the
following to occur:
(a) the public announcement by the Company or by any
person (which shall not include the Company, any subsidiary
of the Company or any employee benefit plan of the Company
or of any subsidiary of the Company) ("Person") that such
Person, who or which, together with all Affiliates and
Associates (within the meanings ascribed to such terms in
Rule 12b-2 of the Securities Exchange Act of 1933 [the
"Exchange Act"]) of such Person, shall be the beneficial
owner of twenty percent (20%) or more of the voting stock
then outstanding;
(b) the commencement of, or after the first public
announcement of any Person to commence, a tender or exchange
offer the consummation of which would result in any Person
becoming the beneficial owner of voting stock aggregating
thirty percent (30%) or more of the then outstanding voting
stock;
(c) the announcement of any transaction relating to
the Company required to be described pursuant to the
requirements of Item 6(e) of Schedule 14A of Regulation 14A
of the Securities and Exchange Commission under the Exchange
Act;
(d) a proposed change in the constituency of the Board
such that, during any period of two (2) consecutive years,
individuals who at the beginning of such period constitute
the Board cease for any reason to constitute at least a
majority thereof, unless the election or nomination for
election by the shareholders of the Company of each new
director was approved by a vote of at least two-third (2/3)
of the directors then still in office who were members of
the Board at the beginning of the period; or
(e) the Company enters into an agreement of merger,
consolidation, share exchange or similar transaction with
any other corporation other than a transaction which would
result in the Company's voting stock outstanding immediately
prior to the consummation of such transaction continuing to
represent (either by remaining outstanding or by being
converted into voting stock of the surviving entity) at
least two-thirds of the combined voting power of the
Company's or such surviving entity's outstanding voting
stock immediately after such transaction;
(f) the Board approves a plan of liquidation or
dissolution of the Company or an agreement for the sale or
disposition by the Company (in one transaction or a series
of transactions) of all or substantially all of the
Company's assets to a person or entity which is not an
affiliate of the Company other than a transaction(s) for the
purpose of dividing the Company's assets into separate
distribution, transmission or generation entities or such
other entities as the Company may determine.
(g) any other event which shall be deemed by a
majority of the Executive Committee of the Board to
constitute a "Change in Control."
2.6 Change in Control Period. "Change in Control Period"
shall mean the period beginning with a Change in Control as
defined in Section 2.5 and ending with the earlier of: (I)
termination date of the Change in Control as determined by the
Compensation Committee or (ii) 24 months following the
consummation of a Change in Control
2.7 Company. "Company" shall mean the Idaho Power Company,
an Idaho corporation, its successors and assigns.
2.8 Compensation Committee. "Compensation Committee" shall
mean the Board committee assigned responsibility for
administering Executive Compensation.
2.9 Contract of Participation. "Contract of Participation"
shall mean an agreement of participation in the Idaho Power
Security Plan for Board of Directors between the Participant and
the Employer, in the form attached as Appendix A.
2.10 Employer. "Employer" shall mean the Company and any
affiliated or subsidiary corporation designated by the Board, or
any successors to the business thereof.
2.11 Participant. "Participant" shall mean any individual
who is elected to the Board and who has executed a Contract of
Participation.
2.12 Plan Anniversary Date. "Plan Anniversary Date" shall
mean February 1 of any year.
2.13 Plan Year. "Plan Year" shall mean the calendar year
effective November 30, 1994.
2.14 Supplemental Retirement Benefit. "Supplemental
Retirement Benefit" shall mean a benefit determined under
Article V of this Plan.
2.15 Year of Service. "Year of Service" shall mean each
twelve (12) months of service on the Board.
ARTICLE III
PARTICIPATION AND VESTINGARTICLE III
3.1 Participation. Effective November 30, 1994,
participation in the Plan shall be limited to outside directors
who elect to participate in this Plan by executing a Contract of
Participation. Inside directors who were Participants on
November 30, 1994, shall receive their vested accrued benefit as
provided in Section 4.1(b) and Article V.
3.2 Fee Reduction. Effective November 30, 1994, no
additional or future fee reduction will be required.
3.3 Vesting. Participants shall be one hundred percent
(100%) immediately vested in their accrued benefit.
ARTICLE IV
SURVIVOR BENEFITS
4.1 Death Benefit.
(a) For all Participants who are first elected to the
Board after November 30, 1994, the survivor benefit shall be
as follows:
(i) If a Participant's death occurs prior to
severance from service on the Board and commencement of
the Supplemental Retirement Benefit, the Employer shall
pay a survivor benefit to such Participant's
Beneficiary as follows:
(a) Amount. The pre-termination survivor
benefit shall be equal to sixty-six and two-thirds
percent (66 2/3%) of the Supplemental Retirement
Benefit calculated under Article V. A Participant
shall be considered to have a minimum of five (5)
Years of Service for purposes of this calculation.
(b) Payment. If the Participant is married
on the date of death, the benefits shall be paid
for the life of the spouse. If the spouse's date
of birth is more than ten (10) years after the
Participant's date of birth, the monthly benefit
shall be reduced to the Actuarial Equivalent of
the above benefit, assuming the above benefit is
payable to a spouse ten (10) years younger than
the Participant. If the Participant is unmarried
on the date of death, the benefit shall be paid to
the Participant's Beneficiary in a lump sum equal
to the value of a death benefit payable to an
assumed spouse the same age as the Participant.
(ii) If a Participant's death occurs after
termination from service on the Board but prior to
commencement of the Supplemental Retirement Benefit,
the Employer shall pay a survivor benefit to said
Participant's Beneficiary as follows:
(a) Amount. The amount of the post-
termination survivor benefit shall be equal to
sixty-six and two-thirds percent (66 2/3%) of the
Supplemental Retirement Benefit payable to the
Participant.
(b) Payment. If the Participant is married
on the date of death, the benefits shall be paid
for the life of the spouse. If the spouse's date
of birth is more than ten (10) years after the
Participant's date of birth, the monthly benefit
shall be reduced to the Actuarial Equivalent of
the above benefit, assuming the above benefit is
payable to a spouse ten (10) years younger than
Participant. If the Participant is unmarried on
the date of death, the benefit shall be paid to
the Participant's Beneficiary in a lump sum equal
to the value of a death benefit payable to an
assumed spouse the same age as the Participant.
(iii) Death After Commencement of Benefits.
If a Participant dies after commencement of benefits, a
survivor benefit will be paid only if, and to the
extent provided for, under the form of benefit elected
by the Participant.
(b) For all Participants who are first elected to the
Board on or prior to November 30 1994, the survivor benefit
shall be as follows:
(i) If a Participant's death occurs prior to
commencement of the Supplemental Retirement Benefit,
the Participant's Beneficiaries shall receive the
death benefit described below unless the Participant's
Beneficiary elects to receive the death benefits
provided for in Section 4.1(a)(i) in lieu of this
benefit. The death benefit will be determined by the
Participant's Years of Service, including Years of
Service after November 30, 1994, at death as set forth
in the schedule below:
YEARS OF MONTHLY ANNUAL
SERVICE BENEFIT BENEFIT
1 $ 291.67 $ 3,500
2 583.33 7,000
3 875.00 10,500
4 1,166.67 14,000
5 and over 1,458.33 17,500
The death benefits shall be paid to the Beneficiary in
equal monthly installments for the period of one
hundred eighty (180) months without interest. Payments
shall commence on the tenth day of the month following
receipt by the Administrative Committee of proof of
Participant's death.
(ii) Death After Commencement of Benefits.
a) A Participant who did not elect to
receive the Supplemental Retirement Benefit in the
grandfathered form as provided for in Section 5.4,
and dies at any time after severance from service
on the Board and after the commencement of the
Supplemental Retirement Benefit, the Participant's
Beneficiary shall receive a survivor benefit to
the extent provided for under the form of benefit
elected by the Participant.
b) A Participant who elected to receive the
Supplemental Retirement Benefit in the
grandfathered form as provided for in Section 5.4
and dies at any time after severance from service
on the Board and after the commencement of the
Supplemental Retirement Benefit, the Participant's
Beneficiaries shall receive the balance, if any,
of the 180-month Supplemental Retirement Benefit.
Receipt by the Participant's Beneficiaries of the
benefit under this subparagraph shall be in lieu
of all other survivor benefits under this Plan.
4.2 Suicide. In the event a Participant commits suicide
within one (1) year of initially entering this Plan, no benefits
shall be payable hereunder to the Participant's Beneficiaries.
ARTICLE V
RETIREMENT BENEFITS
5.1 Benefit. Upon severance of service on the Board, each
Participant shall be entitled to receive, at the time specified
in Section 5.3 below, a Supplemental Retirement Benefit, the
amount of which will be determined by the Participant's Years of
Service on the Plan Anniversary Date immediately preceding or
coinciding with his severance date as set forth below:
YEARS OF MONTHLY ANNUAL
SERVICE BENEFIT BENEFIT
1 $ 291.67 $3,500
2 583.33 7,000
3 875.00 10,500
4 1,166.67 14,000
5 and over 1,458.33 17,500
5.2 Form of Payment The Supplemental Retirement Benefit
shall be paid in the basic form provided below unless the
Participant elects in the calendar year prior to retirement or
termination an Actuarial Equivalent form of benefit provided in
this section. Participants elected to the Board prior to
November 30, 1994, may elect a grandfathered form of benefit as
provided in Section 5.4 in lieu of any other form of benefit.
(a) Normal Form of Benefit Payment. The normal form
of payment shall be a single-life annuity for the lifetime
of the Participant.
(b) Actuarial Equivalent Forms of Benefit.
(i) A joint and survivor annuity with payments
continued to the survivor at an amount equal to two-
thirds (2/3) of the Participant's benefits.
(ii) A joint and survivor annuity with payments
continued to the survivor at an amount equal to the
Participant's benefits.
5.3 Commencement of Benefit Payment.
(a) Outside Directors. The Supplemental Retirement
Benefit shall be paid to an outside director Participant
commencing on the tenth (10th) day of the month immediately
following the later of age sixty-five (65) or severance from
service on the Board as an outside director.
(b) Inside Directors. The Supplemental Retirement
Benefit shall be paid to an inside director Participant
commencing on the tenth (10th) day of the month immediately
following severance from service on the Board.
5.4 Grandfathered Form of Benefit. A Participant first
elected to the Board prior to November 30, 1994, may elect a
grandfathered form of benefit. This grandfathered form of
benefit shall be paid in 180 equal monthly installments in an
amount set forth in Section 5.1. The election shall be made
prior to the Participant's termination.
ARTICLE VI
BENEFICIARY DESIGNATION
6.1 Beneficiary Designation. The Primary Beneficiary shall
be the Participant's spouse. Each Participant, in the event the
Participant's spouse predeceases the Participant or if the
Participant is unmarried, shall have the right, at any time, to
designate any person or persons as Beneficiary or Beneficiaries
(both principal as well as contingent) to whom payment under this
Plan shall be made in the event of death prior to complete
distribution to Participant of the benefits due Participant under
the Plan.
6.2 Amendments, Marital Status, No Participant Designation.
Any Beneficiary designation form may be changed by a Participant
by the filing of a written form prescribed by the Administrative
Committee. The filing of a new Beneficiary designation form will
cancel all Beneficiary designations previously filed. Any
finalized divorce or marriage (other than common law) of a
Participant subsequent to the date of filing of a Beneficiary
designation form shall automatically revoke the prior
designation. If a Participant fails to designate a Beneficiary
as provided above, or if the Beneficiary designation is revoked
by marriage or divorce, without execution of a new designation,
or if all designated Beneficiaries predecease the Participant or
die prior to complete distribution of the Participant's benefits,
then Participant's designated Beneficiary shall be deemed to be
the person or persons surviving the Participant in the first of
the following classes in which there is a survivor, share and
share alike:
(a) the Participant's surviving spouse;
(b) the Participant's children, except that if any of
the children predecease the Participant but leaves issue
surviving, the issue shall take by right of representation;
(c) the Participant's personal representative
(executor or administrator).
6.3 Effect of Payment. The payment to the Beneficiary
shall completely discharge Employer's obligations under this
Plan.
ARTICLE VII
TERMINATION, SUSPENSION OR AMENDMENT OF PLAN
7.1 Termination, Suspension or Amendment of Plan. The Board
may, in its sole discretion, terminate or suspend this Plan at
any time or from time to time, in whole or in part. Either the
Board or the Administrative Committee may amend this Plan at any
time or from time to time. Any amendment may provide different
benefits or amounts of benefits from those herein set forth.
However, no such termination, suspension or amendment shall
adversely affect the benefits of Participants vested therein
prior to such action, the benefits of any Participant who has
retired, or the Beneficiary of any Participant who has died.
7.2 Change in Control. Notwithstanding Section 7.1 above,
during a Change in Control Period, neither the Board nor the
Administrative Committee may terminate this Plan with regard to
accrued benefits of current Participants. No amendment may be
made to the Plan during a Change in Control Period which would
adversely affect the accrued benefits of current Participants,
the benefits of any Participant who has retired, or the
Beneficiary of any Participant who has died. The Plan shall
continue to operate and be effective with regard to all current
or retired Participants and their Beneficiaries during any Change
in Control Period.
ARTICLE VIII
ADMINISTRATION
8.1 Administrative Committee; Duties. This Plan shall be
administered by an Administrative Committee which shall consist
of not less than three (3) nor more than five (5) persons
appointed by the Compensation Committee. Members of the
Administrative Committee may be Participants under this Plan.
The Administrative Committee shall have the authority to make,
amend, interpret and enforce all appropriate rules and
regulations for the administration of this Plan and decide or
resolve any and all questions including interpretations of this
Plan, as may arise in connection with the Plan. A majority vote
of the Administrative Committee members shall control any
decision.
In the administration of this Plan, the Administrative
Committee may, from time to time, employ agents and delegate to
them such administrative duties as it sees fit and may from time
to time consult with counsel who may be counsel to the Employer.
Subject to Article IX, the decision or action of the
Administrative Committee in respect of any questions arising out
of, or in connection with, the administration, interpretation and
application of the Plan and the rules and regulations promulgated
hereunder shall be final and conclusive and binding upon all
persons having any interest in the Plan.
8.2 Indemnity of Administrative Committee. To the extent
permitted by applicable law, the Employer shall indemnify, hold
harmless and defend the Administrative Committee against any and
all claims, loss, damage, expense or liability arising from any
action or failure to act with respect to this Plan, provided that
the Administrative Committee was acting in accordance with the
applicable standard of care. The indemnity provisions set forth
in this Article shall not be deemed to restrict or diminish in
any way any other indemnity available to the Administrative
Committee members in accordance with the Article or By-laws of
the Company.
ARTICLE IX
CLAIMS PROCEDURE
9.1 Claim. Any person claiming a benefit, requesting an
interpretation or ruling under the Plan, or requesting
information under the Plan shall present the request in writing
to the Administrative Committee which shall respond in writing as
soon as practicable.
9.2 Denial of Claim. If the claim or request is denied,
the written notice of denial shall state:
(a) the reason for denial, with specific reference to
the Plan provisions on which the denial is based;
(b) a description of any additional material or
information required and an explanation of why it is
necessary; and
(c) an explanation of the Plan's claim review
procedure.
9.3 Review of Claim. Any person whose claim or request is
denied or who has not received a response within thirty (30) days
may request review by notice given in writing to the
Administrative Committee. The claim or request shall be reviewed
by the Administrative Committee who may, but shall not be
required to, grant the claimant a hearing. On review, the
claimant may have representation, examine pertinent documents,
and submit issues and comments in writing.
9.4 Final Decision. The decision on review shall normally
be made within sixty (60) days. If an extension of time is
required for a hearing or other special circumstances, the
claimant shall be notified, and the time limit shall be one
hundred twenty (120) days. The decision shall be in writing and
shall state the reason and the relevant Plan provisions. All
decisions on review shall be final and bind all parties
concerned.
ARTICLE X
MISCELLANEOUS
10.1 Unfunded Plan. This Plan is intended to be an unfunded
plan maintained primarily to provide deferred compensation
benefits for a select group of "management or highly compensated
employees" within the meaning of Sections 201, 301 and 401 of the
Employee Retirement Income Security Act of 1974, as amended
("ERISA"), and therefore to be exempt from the provisions of
Parts 2, 3 and 4 of Title I of ERISA.
10.2 Unsecured General Creditor. Participants and their
Beneficiaries, heirs, successors and assigns shall have no legal
or equitable rights, interest or claims in any property or asset
of the Employer, nor shall they be Beneficiaries of, or have any
rights, claims or interests in any life insurance policies,
annuity contracts or the proceeds therefrom owned or which may be
acquired by the Employer. Except as may be provided in
Section 10.3, such policies, annuity contracts or other assets of
the Employer shall not be held under any trust for the benefit of
Participants, their Beneficiaries, heirs, successors or assigns,
or held in any way as collateral security for the fulfilling of
the obligation of the Employer under this Plan. Any and all of
the Employer's assets and policies shall be, and remain, the
general, unpledged, unrestricted assets of the Employer. The
Employer's obligation under the Plan shall be that of an unfunded
and unsecured promise to pay money in the future.
10.3 Trust Fund. The Employer shall be responsible for the
payment of all benefits provided under the Plan. At its
discretion, the Employer may establish one or more trusts, with
such trustees as the Board may approve, for the purpose of
providing for the payment of such benefits. Such trust or trusts
may be irrevocable, but the assets thereof shall be subject to
the claims of the Employer's creditors. To the extent any
benefits provided under the Plan are actually paid from any such
trust, the Employer shall have no further obligation with respect
thereto, but to the extent not so paid, such benefits shall
remain the obligation of, and shall be paid by, the Employer.
10.4 Nonassignability. Neither a Participant nor any other
person shall have any right to commute, sell, assign, transfer,
pledge, anticipate, mortgage or otherwise encumber, transfer,
hypothecate or convey in advance of actual receipt the amounts,
if any, payable hereunder, or any part thereof, which are, and
all rights to which are, expressly declared to be unassignable
and nontransferable. No part of the amount payable shall, prior
to actual payment, be subject to seizure or sequestration for the
payment of any debts, judgments, alimony or separate maintenance
owed by a Participant or any other person, nor be transferable by
operation of law in the event of Participant's or any other
person's bankruptcy or insolvency.
10.5 Governing Law. The provisions of this Plan shall be
construed, interpreted and governed in all respects in accordance
with the applicable federal law and, to the extent not preempted
by such federal law, in accordance with the laws of the State of
Idaho without regard to the principles of conflicts of laws.
10.6 Validity. If any provision of this Plan shall be held
illegal or invalid for any reason, the remaining provisions shall
nevertheless continue in full force and effect without being
impaired or invalidated in any way.
10.7 Notice. Any notice or filing required or permitted to
be given under the Plan shall be sufficient if in writing and
hand delivered, or sent by registered or certified mail or fax.
The notice shall be deemed given as of the date of delivery or,
if delivery is made by mail, as of the date shown on the postmark
on the receipt for registration or certification.
10.8 Successors. Subject to Section 7.1, the provisions of
the Plan shall bind and inure to the benefit of the Employer and
its successors and assigns. The term successors as used herein
shall include any corporation or other business entity which
shall, whether by merger, consolidation, purchase or otherwise
acquire all or substantially all of the business and assets of
the Employer, and successors of any such corporation or other
business entity.
10.9 Payment to Guardian. If a Plan benefit is payable to a
minor or a person declared incompetent or to a person incapable
of handling the disposition of property, the Administrative
Committee may direct payment of such Plan benefit to the
guardian, legal representative or person having the care and
custody of the minor, incompetent or person. The Administrative
Committee may require proof of incompetency, minority, incapacity
or guardianship, as it may deem appropriate, prior to
distribution of the Plan benefit. The distribution shall
completely discharge the Administrative Committee and the
Employer from all liability with respect to such benefit.
10.10 Accelerated Distribution. Notwithstanding any
other provision of the Plan, a Participant shall be entitled to
receive, upon written request to the Administrative Committee, a
lump sum distribution equal to ninety percent (90%) of the
Actuarial Equivalent vested accrued Security Plan Retirement
Benefit, as of the date thirty (30) days after notice is given to
the Administrative Committee. The remaining balance of ten
percent (10%) shall be forfeited by the Participant. The amount
payable under this section shall be paid in a lump sum with ten
(10) days following the thirty (30) day period outlined above.
If a Participant requests and obtains an accelerated distribution
under this Section 10.10 and remains employed by the Company,
participation will cease and therewill be no future benefit
accruals under this Plan. Following the death of a Participant,
the Beneficiary may, at any time, request an accelerated
distribution under this section. If the deceased Participant
named multiple Beneficiaries, then all named Beneficiaries must
consent to an request and accelerated distribution. The benefit
payable to the Beneficiary shall be equal to ninety percent (90%)
of the Actuarial Equivalent of the security Plan Retirement
Benefit payable to the Beneficiary. Payment of an accelerated
distribution pursuant to this Section 10.10 shall completely
discharge the Employer's obligation to the Participant and any
Beneficiaries under this Plan.
Adopted this ____ day of ___________________________, 1996.
IDAHO POWER COMPANY
______________________________
______
Chairman
APPENDIX A
CONTRACT OF PARTICIPATION IN THE
IDAHO POWER COMPANY SECURITY PLAN
FOR BOARD OF DIRECTORS
NAME OF PARTICIPANT:
DATE OF BIRTH:
SECURITY PLAN ENTRY DATE:
BENEFICIARY:
This Agreement is made and entered into as of the date written
hereinbelow by and between Idaho Power Company and
. This Agreement is subject to all of the terms of the Idaho Power
Company Security Plan for Board of Directors, as amended and restated
November 30, 1994 (The "Plan"). By signing this agreement,
Participant acknowledges receipt of a copy of the Plan document.
PARTICIPANT IDAHO POWER COMPANY
BY BY
PARTICIPANT CHAIRMAN
DATE DATE
<TABLE>
<CAPTION>
Ex-12
IDACORP, Inc.
Consolidated Financial Information
Ratio of Earnings to Fixed Charges
Twelve Months Ended December 31,
(Thousands of Dollars)
1994 1995 1996 1997 1998
<S> <C> <C> <C> <C> <C>
Earnings, as defined:
Income before income taxes.................. $101,775 $127,342 $135,247 $133,570 $133,806
Adjust for distributed income of equity
investees................................. 326 (2,058) (1,413) (3,943) (4,697)
Equity in loss of equity method investments. 0 0 0 0 458
Minority interest in losses of majority
owned subs................................ 0 0 0 0 (125)
Fixed charges, as below..................... 66,324 70,215 70,418 69,634 69,923
Total earnings, as defined.............. $168,425 $195,499 $204,252 $199,261 $199,365
Fixed charges, as defined:
Interest charges............................ $54,433 $56,456 $57,348 $60,761 $60,677
Preferred stock dividends of subsidiaries-
gross up-Idcrp rate....................... 11,097 12,834 12,079 7,891 8,445
Rental interest factor...................... 794 925 991 982 801
Total fixed charges, as defined......... $66,324 $70,215 $70,418 $69,634 $69,923
Ratio of earnings to fixed charges.............. 2.54x 2.78x 2.90x 2.86x 2.85x
Exhibit 12
</TABLE>
<TABLE>
<CAPTION>
Ex-12a
IDACORP, Inc.
Consolidated Financial Information
Supplemental Ratio of Earnings to Fixed Charges
Twelve Months Ended December 31,
(Thousands of Dollars)
1994 1995 1996 1997 1998
<S> <C> <C> <C> <C> <C>
Earnings, as defined:
Income before income taxes.................. $101,775 $127,342 $135,247 $133,570 $133,806
Adjust for distributed income of equity
investees................................. 326 (2,058) (1,413) (3,943) (4,697)
Equity in loss of equity method
investments............................... 0 0 0 0 458
Minority interest in losses of
majority owned subs....................... 0 0 0 0 (125)
Supplemental fixed charges, as below........ 68,946 72,826 73,018 72,208 72,496
Total earnings, as defined.............. $171,047 $198,110 $206,852 $201,835 $201,938
Fixed charges, as defined:
Interest charges............................ $54,433 $56,456 $57,348 $60,761 $60,677
Preferred stock dividends of subsidiaries-
gross up-Idcrp rate....................... 11,097 12,834 12,079 7,891 8,445
Rental interest factor...................... 794 925 991 982 801
Total fixed charges..................... 66,324 70,215 70,418 69,634 69,923
Supplemental increment to fixed charges*.... 2,622 2,611 2,600 2,574 2,573
Total supplemental fixed charges........ $68,946 $72,826 $73,018 $72,208 $72,496
Supplemental ratio of earnings to fixed charges. 2.48x 2.72x 2.83x 2.80x 2.79x
* Explanation of increment:
Interest on the guaranty of American Falls Reservoir District bonds
and Milner Dam Inc. notes which are already included in operating expense.
Exhibit 12-A
</TABLE>
<TABLE>
<CAPTION>
Ex-12b
IDACORP, Inc.
Consolidated Financial Information
Ratio of Earnings to Combined Fixed Charges and Preferred Dividends Requirements
Twelve Months Ended December 31,
(Thousands of Dollars)
1994 1995 1996 1997 1998
<S> <C> <C> <C> <C> <C>
Earnings, as defined:
Income before income taxes.................. $101,775 $127,342 $135,247 $133,570 $133,806
Adjust for distributed income of equity
investees................................. 326 (2,058) (1,413) (3,943) (4,697)
Equity in loss of equity method
investments............................... 0 0 0 0 458
Minority interest in losses of majority
owned subs................................ 0 0 0 0 (125)
Fixed charges, as below..................... 66,324 70,215 70,418 69,634 69,923
Total earnings, as defined.............. $168,425 $195,499 $204,252 $199,261 $199,365
Fixed charges, as defined:
Interest charges............................ $54,433 $56,456 $57,348 $60,761 $60,677
Preferred stock dividends of subsidiaries-
gross up-Idcrp rate....................... 11,097 12,834 12,079 7,891 8,445
Rental interest factor...................... 794 925 991 982 801
Total fixed charges..................... 66,324 70,215 70,418 69,634 69,923
Preferred dividends requirements............ 0 0 0 0 0
Total combined fixed charges and
preferred dividends................... $66,324 $70,215 $70,418 $69,634 $69,923
Ratio of earnings to combined fixed charges
and preferred dividends....................... 2.54x 2.78x 2.90x 2.86x 2.85x
Exhibit 12-B
</TABLE>
<TABLE>
<CAPTION>
Ex-12c
IDACORP, Inc.
Consolidated Financial Information
Supplemental Ratio of Earnings to Combined Fixed Charges and Preferred Dividends Requirements
Twelve Months Ended December 31,
(Thousands of Dollars)
1994 1995 1996 1997 1998
<S> <C> <C> <C> <C> <C>
Earnings, as defined:
Income before income taxes.................. $101,775 $127,342 $135,247 $133,570 $133,806
Adjust for distributed income of equity
investees................................. 326 (2,058) (1,413) (3,943) (4,697)
Equity in loss of equity method
investments............................... 0 0 0 0 458
Minority interest in losses of majority
owned subs................................ 0 0 0 0 (125)
Supplemental fixed charges and Pref Div,
as below.................................. 68,946 72,826 73,018 72,208 72,496
Total earnings, as defined.............. $171,047 $198,110 $206,852 $201,835 $201,938
Fixed charges, as defined:
Interest charges............................ $54,433 $56,456 $57,348 $60,761 $60,677
Preferred stock dividends of subsidiaries-
gross up-Idcrp rate....................... 11,097 12,834 12,079 7,891 8,445
Rental interest factor...................... 794 925 991 982 801
Total fixed charges..................... 66,324 70,215 70,418 69,634 69,923
Supplemental increment to fixed charges*.... 2,622 2,611 2,600 2,574 2,573
Supplemental fixed charges.................. 68,946 72,826 73,018 72,208 72,496
Preferred dividends requirements............ 0 0 0 0 0
Total combined supplemental fixed charges
and preferred dividends............... $68,946 $72,826 $73,018 $72,208 $72,496
Supplemental ratio of earnings to combined fixed
charges and preferred dividends.............. 2.48x 2.72x 2.83x 2.80x 2.79x
* Explanation of increment: Exhibit 12-C
interest on the guaranty of American Falls District bonds
and Milner Dam Inc. notes which are already included in operating expense.
</TABLE>
<TABLE>
<CAPTION>
Ex-12d
Idaho Power Company
Consolidated Financial Information
Ratio of Earnings to Fixed Charges
Twelve Months Ended December 31,
(Thousands of Dollars)
1994 1995 1996 1997 1998
<S> <C> <C> <C> <C> <C>
Earnings, as defined:
Income before income taxes.................. $109,173 $135,333 $142,710 $138,746 $140,984
Adjust for distributed income of equity
investees................................. 326 (2,058) (1,413) (3,943) (4,697)
Equity in loss of equity method
investments............................... 0 0 0 0 476
Minority interest in losses of majority
owned subs................................ 0 0 0 0 (125)
Fixed charges, as below..................... 55,227 57,381 58,339 61,743 61,478
Total earnings, as defined.............. $164,726 $190,656 $199,636 $196,546 $198,116
Fixed charges, as defined:
Interest charges............................ $54,433 $56,456 $57,348 $60,761 $ 60,677
Rental interest factor...................... 794 925 991 982 801
Total fixed charges, as defined....... $55,227 $57,381 $58,339 $61,743 $61,478
Ratio of earnings to fixed charges.............. 2.98x 3.32x 3.42x 3.18x 3.22x
Exhibit 12-D
</TABLE>
<TABLE>
<CAPTION>
Ex-12e
Idaho Power Company
Consolidated Financial Information
Supplemental Ratio of Earnings to Fixed Charges
Twelve Months Ended December 31,
(Thousands of Dollars)
1994 1995 1996 1997 1998
<S> <C> <C> <C> <C> <C>
Earnings, as defined:
Income before income taxes.................. $109,173 $135,333 $142,710 $138,746 $140,984
Adjust for distributed income of equity
investees................................. 326 (2,058) (1,413) (3,943) (4,697)
Equity in loss of equity method
investments............................... 0 0 0 0 476
Minority interest in losses of majority
owned subs................................ 0 0 0 0 (125)
Supplemental fixed charges, as below........ 57,849 59,992 60,939 64,317 64,051
Total earnings, as defined.............. $167,348 $193,267 $202,236 $199,120 $200,689
Fixed charges, as defined:
Interest charges............................ $54,433 $56,456 $57,348 $60,761 $60,677
Rental interest factor...................... 794 925 991 982 801
Total fixed charges..................... 55,227 57,381 58,339 61,743 61,478
Supplemental increment to fixed charges*.... 2,622 2,611 2,600 2,574 2,573
Total supplemental fixed charges........ $57,849 $59,992 $60,939 $64,317 $64,051
Supplemental ratio of earnings to fixed charges. 2.89x 3.22x 3.32x 3.10x 3.13x
* Explanation of increment:
Interest on the guaranty of American Falls Reservoir District bonds
and Milner Dam Inc. notes which are already included in operating expense.
Exhibit 12-E
</TABLE>
<TABLE>
<CAPTION>
Ex-12f
Idaho Power Company
Consolidated Financial Information
Ratio of Earnings to Combined Fixed Charges and Preferred Dividends Requirements
Twelve Months Ended December 31,
(Thousands of Dollars)
1994 1995 1996 1997 1998
<S> <C> <C> <C> <C> <C>
Earnings, as defined:
Income before income taxes.................. $109,173 $135,333 $142,710 $138,746 $140,984
Adjust for distributed income of equity
investees................................. 326 (2,058) (1,413) (3,943) (4,697)
Equity in loss of equity mehtod
investments............................... 0 0 0 0 476
Minority interest in losses of majority
owned subs................................ 0 0 0 0 (125)
Fixed charges, as below..................... 55,227 57,381 58,339 61,743 61,478
Total earnings, as defined.............. $164,726 $190,656 $199,636 $196,546 $198,116
Fixed charges, as defined:
Interest charges............................ $54,433 $56,456 $57,348 $60,761 $60,677
Rental interest factor...................... 794 925 991 982 801
Total fixed charges..................... 55,227 57,381 58,339 61,743 61,478
Preferred stock dividends-gross up-Ipc
rate...................................... 10,682 12,392 12,146 7,803 8,275
Total combined fixed charges and
preferred dividends.................. 65,909 $69,773 $70,485 $69,546 $69,753
Ratio of earnings to combined fixed charges and
preferred dividends.......................... 2.50x 2.73x 2.83x 2.83x 2.84x
Exhibit 12-F
</TABLE>
<TABLE>
<CAPTION>
Ex-12g
Idaho Power Company
Consolidated Financial Information
Supplemental Ratio of Earnings to Combined Fixed Charges and Preferred Dividends Requirements
Twelve Months Ended December 31,
(Thousands of Dollars)
1994 1995 1996 1997 1998
<S> <C> <C> <C> <C> <C>
Earnings, as defined:
Income before income taxes.................. $109,173 $135,333 $142,710 $138,746 $140,984
Adjust for distributed income of equity
investees................................. 326 (2,058) (1,413) (3,943) (4,697)
Equity in loss of equity method
investments............................... 0 0 0 0 476
Minority interest in losses of majority
owned subs................................ 0 0 0 0 (125)
Supplemental fixed charges and Pref Div,
as below.................................. 57,849 59,992 60,939 64,317 64,051
Total earnings, as defined.............. $167,348 $193,267 $202,236 $199,120 $200,689
Fixed charges, as defined:
Interest charges............................ $54,433 $56,456 $57,348 $60,761 $60,677
Rental interest factor...................... 794 925 991 982 801
Total fixed charges..................... 55,227 57,381 58,339 61,743 61,478
Supplemental increment to fixed charges*.... 2,622 2,611 2,600 2,574 2,573
Supplemental fixed charges.................. 57,849 59,992 60,939 64,317 64,051
Preferred stock dividends-gross up-Ipc
rate...................................... 10,682 12,392 12,146 7,803 8,275
Total combined supplemental fixed
charges and preferred dividends...... $68,531 $72,384 $73,085 $72,120 $72,326
Supplemental ratio of earnings to combined fixed
charges and preferred dividends.............. 2.44x 2.67x 2.77x 2.76x 2.77x
* Explanation of increment: Exhibit 12-G
interest on the guaranty of American Falls District bonds
and Milner Dam Inc. notes which are already included in operating expense.
</TABLE>
EXHIBIT 21
SUBSIDIARIES OF REGISTRANTS
IDACORP, Inc:
1. Idaho Power Company (incorporated in Idaho)
2. Ida-West Energy Company (incorporated in Idaho)
3. IDACORP Energy Solutions Co. (incorporated in Nevada)
4. IDACORP Energy Services Co. (incorporated in Nevada)
5. IDACORP Energy Solutions L.P. (a Delaware limited
partnership)
Idaho Power Company
1. Idaho Energy Resources Company (incorporated in
Wyoming)
2. IDACORP Financial Services, Inc. (incorporated in
Idaho)
3. Stellar Dynamics Inc. (incorporated in Idaho)
4. Idaho Power Resources Corporation (incorporated in
Idaho)
5. Applied Power Corporation (incorporated in Washington)
6. Idaho Power Diversified Enterprises Co. (incorporated
in Idaho)
7. Pathnet/Idaho Power Equipment, LLC (a Delaware Limited
Liability Company)
EXHIBIT 23
INDEPENDENT AUDITORS' CONSENT
We consent to the incorporation by reference in Idaho Power
Company's Registration Statement No. 33-51215 on Form S-3
and IDACORP, Inc.'s Registration Statement Nos. 33-56071
and 333-65157 on Form S-8 and Registration Statement Nos.
333-00139 and 333-64737 on Form S-3 of our reports dated
January 29, 1999 on IDACORP, Inc. and Idaho Power Company,
appearing in this Annual Report on Form 10-K of IDACORP,
Inc. and Idaho Power Company for the year ended December
31, 1998.
DELOITTE & TOUCHE LLP
Boise, Idaho
March 19, 1999
WARNING: THE EDGAR SYSTEM ENCOUNTERED ERROR(S) WHILE PROCESSING THIS SCHEDULE.
<TABLE> <S> <C>
<ARTICLE> UT
<LEGEND>
This schedule contains summary financial information extracted from IDACORP,
Inc.(Ex-27A) and is qualified in its entirety by reference to such financial statements.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1998
<PERIOD-END> DEC-31-1998
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 1,711,509
<OTHER-PROPERTY-AND-INVEST> 129,437
<TOTAL-CURRENT-ASSETS> 230,223
<TOTAL-DEFERRED-CHARGES> 380,451
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 2,451,620
<COMMON> 451,564
<CAPITAL-SURPLUS-PAID-IN> 0
<RETAINED-EARNINGS> 278,833
<TOTAL-COMMON-STOCKHOLDERS-EQ> 730,397
0
105,968
<LONG-TERM-DEBT-NET> 802,199
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 13,738
<COMMERCIAL-PAPER-OBLIGATIONS> 38,524
<LONG-TERM-DEBT-CURRENT-PORT> 6,029
0
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 754,765
<TOT-CAPITALIZATION-AND-LIAB> 2,451,620
<GROSS-OPERATING-REVENUE> 1,121,976
<INCOME-TAX-EXPENSE> 44,630
<OTHER-OPERATING-EXPENSES> 930,755
<TOTAL-OPERATING-EXPENSES> 975,385
<OPERATING-INCOME-LOSS> 146,591
<OTHER-INCOME-NET> 8,020
<INCOME-BEFORE-INTEREST-EXPEN> 154,611
<TOTAL-INTEREST-EXPENSE> 65,435
<NET-INCOME> 89,176
0
<EARNINGS-AVAILABLE-FOR-COMM> 89,176
<COMMON-STOCK-DIVIDENDS> 69,868
<TOTAL-INTEREST-ON-BONDS> 52,270
<CASH-FLOW-OPERATIONS> 169,887
<EPS-PRIMARY> 2.37
<EPS-DILUTED> 2.37
</TABLE>
<TABLE> <S> <C>
<ARTICLE> UT
<LEGEND>
This schedule contains summary financial information extracted from Idaho
Power (EX-27B) Company and is qualified in its entirety by reference to such financial
statements.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1998
<PERIOD-END> DEC-31-1998
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 1,710,696
<OTHER-PROPERTY-AND-INVEST> 105,600
<TOTAL-CURRENT-ASSETS> 225,589
<TOTAL-DEFERRED-CHARGES> 379,905
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 2,421,790
<COMMON> 94,031
<CAPITAL-SURPLUS-PAID-IN> 358,333
<RETAINED-EARNINGS> 252,363
<TOTAL-COMMON-STOCKHOLDERS-EQ> 704,727
0
105,968
<LONG-TERM-DEBT-NET> 802,199
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 13,738
<COMMERCIAL-PAPER-OBLIGATIONS> 38,508
<LONG-TERM-DEBT-CURRENT-PORT> 6,029
0
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 750,621
<TOT-CAPITALIZATION-AND-LIAB> 2,421,790
<GROSS-OPERATING-REVENUE> 1,121,976
<INCOME-TAX-EXPENSE> 45,065
<OTHER-OPERATING-EXPENSES> 930,755
<TOTAL-OPERATING-EXPENSES> 975,820
<OPERATING-INCOME-LOSS> 146,156
<OTHER-INCOME-NET> 9,456
<INCOME-BEFORE-INTEREST-EXPEN> 155,612
<TOTAL-INTEREST-EXPENSE> 59,693
<NET-INCOME> 95,919
5,658
<EARNINGS-AVAILABLE-FOR-COMM> 90,261
<COMMON-STOCK-DIVIDENDS> 69,889
<TOTAL-INTEREST-ON-BONDS> 52,279
<CASH-FLOW-OPERATIONS> 173,725
<EPS-PRIMARY> 0
<EPS-DILUTED> 0
</TABLE>
