UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
X ANNUAL REPORT PURSUANT TO SECTION 13 OR 15 (D) OF THE SECURITY
EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2000
OR
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15 (D) OF THE SECURITY
EXCHANGE ACT OF 1934
For the transition period from .............. to...............
Exact name of Registrants
as specified in their charters,
address of principal executive
Commission offices and Registrants' IRS Employer Iden-
File Number 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
Preferred Stock Purchase Rights
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. ( )
Aggregate market value of voting and non-voting common stock held
by nonaffiliates (March 1, 2001)
IDACORP, Inc.: $1,399,591,939
Idaho Power Company: None
Number of shares of common stock outstanding at March 1, 2001:
IDACORP, Inc.: 37,415,746
Idaho Power Company: 37,612,351 shares, all of which are
held by IDACORP, Inc.
Documents Incorporated by Reference:
Part III, Item 10 - 13 Portions of the joint definitive proxy
statement of the Registrant.
to be filed pursuant to Regulation 14A
for the 2001 Annual Meeting of Shareholders
to be held on May 17, 2001.
This Combined Form 10-K represents separate filings by IDACORP,
Inc. and Idaho Power Company. Information contained herein
relating to an individual registrant is filed by that registrant on
its own behalf. Idaho Power Company makes no representations as to
the information relating to IDACORP, Inc.'s other operations.
TABLE OF CONTENTS
PART I
PAGE
ITEM 1. BUSINESS 1
OVERVIEW 1
UTILITY OPERATIONS 1
ELECTRIC INDUSTRY RESTRUCTURING 2
REGULATION 3
RATES 3
POWER SUPPLY 5
FUEL 6
WATER RIGHTS 7
ENVIRONMENTAL REGULATION 7
DIVERSIFIED BUSINESS OPERATIONS 9
ENERGY MARKETING 9
OTHER 10
RESEARCH AND DEVELOPMENT 11
CONSTRUCTION PROGRAM 11
FINANCING PROGRAM 12
ITEM 2. PROPERTIES 13
ITEM 3. LEGAL PROCEEDINGS 15
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS 15
EXECUTIVE OFFICERS OF THE REGISTRANTS 16
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON STOCK AND RELATED
STOCKHOLDER MATTERS 19
ITEM 6. SELECTED FINANCIAL DATA 20
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS 21
ITEM 7A.QUALITATIVE AND QUANTITATIVE DISCLOSURE ABOUT MARKET
RISK 35
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA 37
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE 75
PART III
ITEM 10.DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANTS* 75
ITEM 11.EXECUTIVE COMPENSATION* 75
ITEM 12.SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT* 75
ITEM 13.CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS* 75
PART IV
ITEM 14.EXHIBITS, FINANCIAL STATEMENT SCHEDULE AND REPORTS ON
FORM 8-K 75
SIGNATURES 81
*INCORPORATED BY REFERENCE.
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.
OVERVIEW
IDACORP, Inc. (IDACORP or the Company) is a holding company
incorporated in 1998 under the laws of the state of Idaho. On
October 1, 1998, IDACORP became the parent of Idaho Power Company
(IPC). IPC is a regulated electric utility, and also conducts
IDACORP's unregulated electricity marketing operations.
IDACORP's other significant operating subsidiaries are:
IDACORP Energy - natural gas marketing
Ida-West Energy - independent power projects development and
management
IdaTech - developer of integrated fuel cell systems
IDACORP Financial Services (IFS) - affordable housing and other
real estate investments
Rocky Mountain Communications - commercial and residential
Internet service provider
IDACOMM - provider of telecommunications services
IDACORP Services - energy related products and services
Applied Power Company (APC) - supplier of photovoltaic systems
(sold January 2001).
Ownership of Ida-West was transferred by IPC to IDACORP upon
formation of the holding company in 1998. APC and IFS were
transferred by IPC to IDACORP effective January 1, 2000. At
December 31, 2000, IDACORP had 2,044 full-time employees.
IDACORP has identified two reportable business segments, the
regulated utility operations of IPC, and the energy marketing
activities of IPC and IDACORP Energy. We present information
about our operating segments in Note 12 to the Consolidated
Financial Statements. These segments and our other operations are
described below.
UTILITY OPERATIONS
IPC was incorporated under the laws of the state of Idaho in 1989
as successor to a Maine corporation organized in 1915. IPC in
involved in the generation, purchase, transmission, distribution
and sale of electric energy in a 20,000 square mile area in
southern Idaho, eastern Idaho and northern Nevada, with an
estimated population of 814,000. IPC holds franchises in 72
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, 2000, IPC
supplied electric energy to over 390,000 general business
customers and had 1,713 full-time employees.
IPC owns and operates 17 hydroelectric power plants and shares
ownership in three coal-fired generating plants. These generating
plants and their capacities are listed in Item 2. "Properties."
IPC's coal-fired plants are in Wyoming, Oregon and Nevada, and use
low-sulfur coal from Wyoming and Utah.
IPC relies heavily on hydroelectric power for its generating needs
and is one of the nation's few investor-owned utilities with a
predominantly hydroelectric generating base. Because of its
reliance on hydro generation, IPC's generation operations can be
significantly affected by the weather. The availability of
inexpensive hydroelectric power depends on snowpack in the
mountains above IPC's hydro facilities, precipitation and other
weather and streamflow management considerations. When
hydroelectric generation decreases and customer demand increases,
IPC increases its use of more expensive thermal generation and
purchased power.
The rates we charge to our general business customers are
determined by the various regulatory authorities. Approximately
95 percent of our general business revenue and sales come from
customers in the State of Idaho. The rates we charge these
customers, (except for customers with special contracts) are
adjusted annually by a power cost adjustment (PCA) mechanism. The
PCA adjusts rates to reflect the changes in costs incurred by IPC
to supply power. Throughout the year, we compare our actual power
supply costs to the amounts we are recovering in rates. Most, but
not all, of this difference is deferred and included in the
calculation of rates for future years. The effect of the PCA is
to lessen the impact that water conditions have on earnings. The
PCA is discussed in more detail below in "Rates."
The primary influences on electricity sales are weather and
economic conditions. Generally, extreme temperatures increase
sales to customers, who use electricity for cooling and heating,
and moderate temperatures decrease sales. Precipitation levels
during the growing season affect sales to customers who use
electricity to operate irrigation pumps. Increased precipitation
reduces electricity usage by these customers.
With its predominantly hydroelectric base and low-cost coal-fired
plants, IPC has historically been one of the lowest-cost producers
of electric energy among the nation's investor-owned utilities.
Through its interconnections with the Bonneville Power
Administration (BPA) and other utilities, IPC has access to all
the major electric systems in the West.
For the year ended December 31, 2000, total revenues from
residential customers accounted for 40 percent 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 or more accounted for 24 percent,
and irrigation customers accounted for 13 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 skiing industry.
ELECTRIC INDUSTRY RESTRUCTURING
The legislatures and/or regulatory commissions in several states,
and at a national level, have considered or are considering
various forms of retail competition. In 1997, the Idaho
Legislature appointed a committee to study restructuring of the
electric utility industry. Although the committee will continue
studying a variety of restructuring ideas, it has not recommended
any restructuring legislation and is not expected to in the
foreseeable future. In 1999, the Oregon legislature passed
legislation restructuring the electric utility industry, but
exempted IPC's service territory.
In December 1999, the FERC issued Order No. 2000, dealing with
Regional Transmission Organizations (RTOs), which are discussed
further below in "Power Supply - Transmission Services."
REGULATION
IPC is under the regulatory jurisdiction (as to rates, service,
accounting and other general matters of utility operation) of the
Federal Energy Regulatory Commission (FERC), the Idaho Public
Utilities Commission (IPUC), the Oregon Public Utility Commission
(OPUC) and the Public Utility Commission of Nevada (PUCN). 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 Public Utilities Regulatory
Policy Act of 1978 (PURPA), the state regulatory agencies have
each issued orders and rules regulating IPC's purchase of power
from Cogeneration and Small Power Production (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").
RATES
Idaho Jurisdiction -
IPC has a PCA mechanism that provides for annual adjustments to
the rates charged to its Idaho retail electric 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 IPUC approved IPC's May 16, 2000 PCA adjustment, issuing Order
28358 dated May 9, 2000. This rate adjustment increased Idaho
general business customer rates by 9.5 percent, and resulted from
forecasted below-average hydroelectric generating conditions.
Overall, the PCA adjustment is expected to increase general
business revenue by $38 million during the 2000-2001 rate period,
partially offsetting the forecasted increase in power supply
costs.
So far in the 2000-2001 PCA rate year, actual power supply costs
have been significantly greater than the forecast, due to actual
hydroelectric generation being below the forecast, and purchased
power volumes and prices being substantially above the forecast.
To account for these higher-than-forecasted costs, IPC has
recorded a regulatory asset of $161 million as of January 31,
2001.
In February 2001, IPC filed an application with the IPUC
proposing to implement a one-year emergency fuel charge due to
these extraordinarily high expenses. The IPUC suspended the
proposed effective date of March 26, 2001 to May 1, 2001, to
allow for public workshops and hearings to be held on the matter.
The IPUC also ordered IPC to make its annual PCA filing as soon
as possible so that the cases can be filed jointly.
The May 1999 rate adjustment reduced rates by 9.2 percent. The
decrease was the result of both forecasted above-average
hydroelectric generating conditions for the upcoming year and a
true-up from the 1998-99 rate period. Overall, the May 1999 rate
adjustment decreased annual general business revenue by
approximately $40 million during the 1999-2000 rate period.
The May 1998 rate adjustment increased annual revenue by $34
million over the amount that would have been recorded at the 1997-
98 rates. The 1998-99 forecast had assumed a return to more
normal hydroelectric generating conditions from the above-average
conditions experienced in the prior year. This resulted in
forecasted power supply costs being near the amounts used in base
rates.
IPC had a settlement agreement with the IPUC that expired at the
end of 1999. Under the terms of the settlement, when earnings in
IPC's Idaho jurisdiction exceeded an 11.75 percent return on year-
end common equity, IPC set aside 50 percent of the excess for the
benefit of Idaho retail customers.
In March 2000 IPC submitted its 1999 annual earnings sharing
compliance filing to the IPUC. This filing indicated that there
was almost $9.6 million in 1999 earnings and $2.7 million in
unused 1998 reserve balances available for the benefit of our
Idaho customers.
In April 2000 the IPUC issued Order 28333, which ordered that $6.9
million of the revenue sharing balance be refunded to Idaho
customers through rate reductions effective May 16, 2000. The
Order also approved IPC's continued participation in the Northwest
Energy Efficiency Alliance (NEEA) for the years 2000-2004,
ordering IPC to set aside the remaining $5.4 million of revenue
sharing dollars to fund that participation.
IPC requested that the IPUC allow for the recovery of post-1993
DSM expenses and acceleration of the recovery of DSM expenditures
authorized in the last general rate case. In its Order No. 27660
issued on July 31, 1998, the IPUC set a new amortization period of
12 years instead of the 24-year period previously adopted. On
April 17, 2000, the Idaho Supreme Court affirmed the IPUC order,
after hearing an appeal by a group of industrial customers.
On February 23, 2001, the IPUC approved IPC's Green Energy
Purchase Program. The Green Program is an optional program
available to all IPC customers in Idaho, allowing them to pay a
premium to purchase energy generated by alternative sources such
as solar and wind. Creating the Green Program will provide
additional means for customers to stimulate demand for new green
resources and their development.
Other Jurisdictions -
IPC filed with the OPUC on December 19, 2000 for an accounting
order to defer for later ratemaking treatment excess net power
supply costs expected to be incurred in 2001.
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.
The IPUC has approved IPC's sale of its Nevada service territory
to Raft River Electric Co-Op. This sale transfers the
transmission facilities and rights-of-way that serve about 1,250
customers in northern Nevada and about 90 customers in southern
Idaho. The sale must still be approved by the PUCN. The FERC has
approved a power supply agreement between IPC and Raft River.
This sale will allow IDACORP to participate in a deregulated
electric utility market in the State of Nevada.
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 resources. IPC's system is dual-peaking, with the larger
peak demand generally occurring in the summer. The system peak
demand for 2000 was 2,919 MW, set on July 12, 2000. Peak demands
in 1999 and 1998 were 2,839 MW and 2,747 MW respectively. IPC
expects total system energy requirements to grow 1.8 percent
annually over the next five years.
Every two years, IPC is required to file with the IPUC and OPUC an
Integrated Resource Plan (IRP), a comprehensive look at IPC's
present and future demands for electricity and plan for meeting
that demand. The 2000 IRP identifies a potential electricity
shortfall within IPC's utility service territory by mid-2004. The
IRP projects a 250-MW resource need in 2004 to satisfy energy
demand during IPC's peak periods. Prior to 2004, the IRP calls
for IPC to increase purchases from the Northwest energy markets to
meet short-term energy needs. IPC anticipates that after 2004,
transmission constraints will not allow it to continue to cover
increasing demand by increasing purchases.
IPC issued a request for proposals seeking bids for 250 MW of
additional generation to support the growing demand in its utility
service territory. A proposal by Garnet Energy LLC, a subsidiary
of Ida-West Energy, was selected by IPC. Garnet has proposed
constructing and owning a natural gas-fired turbine facility
near Middleton, Idaho. In January 2001 IPC signed an agreement
with Garnet to define the conditions under which the utility will
purchase energy produced at the 250-MW project.
In March 2001, IPC announced plans to build a 90-MW combustion
turbine power plant near Mountain Home, Idaho. The project is
expected to be completed in July 2001, though it must still
complete environmental and other permitting processes before
construction can begin.
Because of its reliance upon hydroelectric generation, which
varies according to streamflows, IPC's generating system can be
constrained by resource (water) availability. In 1998 and 1999,
IPC's hydro generating system experienced above average water
years, but 2000 has brought below normal water conditions.
Current mountain snowpack above Brownlee Reservoir, the main
storage pool for the Hells Canyon hydro facilities, was at 55
percent of normal in February 2001.
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 no earlier than 2003 and
with Seattle City Light under a contract that expires in 2003.
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 Avista
Corporation, PacifiCorp, The Montana Power Company and Sierra
Pacific Power Company. 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 all major 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 (see RTO discussion below in
"Transmission Services").
CSPP Purchases -
As a result of the enactment of the 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 total cost of power purchased
from CSPP projects was $53.7 million in 2000. During 2000, IPC
purchased 862.3 million kWh of power from these private developers
at a blended price of 6.2 cents per kWh.
The IPUC has 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 and has
limited the length of new contracts to a maximum of five years.
Wholesale Power Sales -
IPC has firm wholesale power sales contracts with several
entities. These contracts are for various amounts of energy, up
to 100 average megawatts, and are of various lengths expiring
between 2001and 2009.
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 December 1999 the FERC, in its landmark Order 2000, said that
all companies with transmission assets must file to form RTOs or
explain why they cannot. Order 2000 is a follow up to orders 888
and 889 issued in 1996, which required transmission owners to
provide non-discriminatory transmission service to third parties.
By encouraging the formation of RTOs, the FERC seeks to further
facilitate the formation of liquid wholesale electricity markets.
In response to FERC Order 2000, IPC and other regional
transmission owners filed in October 2000 a plan to form RTO West,
an independent entity that will operate the transmission grid in
eight western states. RTO West will have its own independent
governing board. The participating transmission owners will retain
ownership of the lines, but will not have a role in operating the
grid.
The FERC filing represents a major portion of the filing necessary
to form RTO West. However, substantial additional filings will be
necessary to include the tariff and integration agreements
associated with the new entity and filings for state approvals. We
expect the FERC filings to be completed by the summer of 2001 and
state filings to be initiated in late 2001 or early 2002.
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
both provide transmission services and reach a broad power sales
market. IPC is a member of both the Western Regional Transmission
Association and the Northwest Regional Transmission Association.
These associations help facilitate transmission access and
planning throughout the power system.
FUEL
IPC, through its subsidiary Idaho Energy Resources Co., owns a one-
third interest in the Bridger Coal Company, which owns the Jim
Bridger 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. The Jim Bridger 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 Black Butte and Leucite Hills mines located near
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.
Sierra Pacific Power Company (SPPCo), with whom IPC is a joint
(50/50) participant in the ownership and operation of the North
Valmy Steam Electric Generating plant (Valmy), has a long-term
coal contract with Southern Utah Fuel Company, a subsidiary of
Canyon Fuel Co., LLC. This contract, which expires on June 30,
2003, calls 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.
In 1986 IPC 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 million 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 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 for at least the next 10 years. 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.
ENVIRONMENTAL REGULATION
Environmental regulation at the federal, state, regional and local
levels is having a continuing impact on IPC's operations due to
the cost of installation and operation of equipment required for
compliance with such regulations 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 2001 and
during the period 2002-2005 will total approximately $11.1 million
and $49.6 million, respectively. Studies related to mitigation of
environmental concerns due to relicensing of hydro facilities will
be a major portion of these expenditures. IPC anticipates
incurring approximately $27.5 million annually of operating
expenses for environmental facilities during the period 2001-2005,
based upon present environmental laws and regulation.
Clean Air -
IPC has analyzed the Clean Air Act 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 material adverse effects upon its operations with
regard to SO2 emissions.
In July 1997 the Environmental Protection Agency (EPA) announced
new National Ambient Air Quality Standards (NAAQS) for ozone and
Particulate Matter (PM) and in July 1999 the EPA announced
regional haze regulations for protection of visibility in national
parks and wilderness areas. On May 14, 1999, a federal court
ruling blocked implementation of these standards, which EPA
proposed in 1997. In November 2000, the EPA appealed to the U.S.
Supreme Court to reconsider that decision. A ruling should be
made on that appeal in mid-2001. Impacts of the ozone and PM
regulations and regional haze regulations on IPC's thermal
operations are unknown at this time.
North Valmy, Boardman and Jim Bridger Unit 4 elected to meet Phase
I nitrogen oxide (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 NO x limits until 2008. Had
the units not voluntarily "early elected," they would have been
required to meet the Phase II limits in 2000. Jim Bridger Units
1, 2, and 3 were accepted as substitution units in 1995 and are
subject to NO x limits of Phase I instead of the more restrictive
limits of Phase II. Jim Bridger has installed low NO x equipment
to reduce NO x 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 period
from May 15 to October 15 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, Shoshone Falls,
Twin Falls, Upper Salmon, Lower Salmon and Bliss 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, 2000, the
investment in these facilities was $12.6 million and the annual
cost of operation pursuant to FERC License 1971 was approximately
$2.6 million annually.
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 Operations - Environmental Issues".)
Hazardous/Toxic Wastes and Substances -
Under the Toxic Substances Control Act (TSCA), the 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 system.
This program will save costs associated with the long-term
monitoring and testing of equipment and grounds for PCB
contamination as well as being good for the environment.. Total
IPC costs for the identification and disposal of PCBs from IPC's
system were $0.8 million, $0.6 million and $0.5 million for 2000,
1999 and 1998 respectively. IPC believes that all generation
facilities are presently non-PCB.
DIVERSIFIED BUSINESS OPERATIONS
IDACORP has been pursuing a strategy of expanding non-regulated
activities and separating the regulated utility operations of IPC
from non-regulated activities. The following discussion
highlights significant developments related to this strategy.
ENERGY MARKETING
To compete as an energy provider of choice, we have built a
trading operation that participates in the electricity, natural
gas and other related markets from our offices in Boise, Idaho and
Houston, Texas. Our energy marketing and trading strategy has
produced increasingly positive results over the last four years.
Our natural gas marketing capability continues to expand as the
electricity and natural gas markets move toward convergence, and
our electricity marketing efforts have resulted in volume and
income increases each year since inception of the strategy.
When buying and selling energy, the high volatility of energy
prices can have significant negative impact on profitability if
not appropriately managed. Also, counterparty creditworthiness is
key to ensuring that transactions entered into withstand dramatic
market fluctuations. To manage the risks inherent in the energy
commodity industry while implementing our business strategy, our
Risk Management Committee, comprised of Company officers, oversees
the risk management program as defined in our risk management
policy. The program is intended to manage the impact to earnings
caused by the volatility of energy prices by mitigating commodity
price risk, credit risk, and other risks related to the energy
commodity business. We discuss some of these risks later in Part
II Item 7 "Management's Discussion and Analysis of Financial
Conditions and Results of Operations - Market Risk."
The IPUC has approved our application to move our nonutility
electricity marketing activity from IPC to another IDACORP
subsidiary, IDACORP Energy. We expect to have FERC approval by
early April 2001. These non-operating transactions do not involve
sales from IPC's resources and are not related to system
reliability.
OTHER
Ida-West Energy Company
Ida-West develops, acquires, owns and manages electric power
projects. In January 2001, IPC chose Garnet Energy, a subsidiary
of Ida-West, to provide additional power that IPC is seeking to
secure. Garnet plans to build a 250-MW natural gas-fired turbine
near Middleton, Idaho, about 20 miles west of Boise. This plant
will have an upgrade potential to 500 MW and will be ready by mid-
2004 to meet IPC's projected need.
In March, 2000, Ida-West sold for cash its interest in the yet-to-
be-built Hermiston Power Project, a 536-MW gas-fired project to be
located near Hermiston, Oregon. Ida-West was responsible for
managing all permitting and development activities relating to the
project since its inception in 1993. Ida-West recorded a pre-tax
gain of $14 million on this transaction in 2000.
Ida-West has investments in 12 operating hydroelectric plants with
a total generating capacity of approximately 72 MW. IPC has
purchased all of the power from the five Idaho hydroelectric
entities that are fifty-percent owned by Ida-West, totaling
approximately $8.1 million in 2000.
Through September 1998, Ida-West was a subsidiary of IPC. On
October 1, 1998, Ida-West was transferred to become a direct
subsidiary of IDACORP.
IdaTech
In March 1999 IDACORP purchased a majority interest in IdaTech
(then known as Northwest Power Systems). IdaTech 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. In 2000 IdaTech completed testing of its patented
alpha fuel cell system for residential applications, and is now
proceeding with design and production of the first 50 beta fuel
cell systems for testing in 2001, as agreed upon in a contract
with the Bonneville Power Administration. IdaTech also began
field testing its fuel cell systems in Japan in cooperation with
Tokyo Boeki, Ltd.
IdaTech is anticipating commercialization of its first units in
2002 in applications such as uninterruptible power sources and
emergency power. Residential units should be available in 2003.
Rocky Mountain Communications, Inc.
In August 2000, IDACORP acquired a controlling interest in Rocky
Mountain Communications, Inc. (RMCI), is a national Internet
service provider, offering traditional and high-speed Internet
access services in both residential and business markets.
RMCI is developing its high-speed Velocitus broadband wireless
Internet service for business applications and is marketing this
service to businesses across the western United States. The
service is currently available in Boise and Pocatello, Idaho and
Spokane, Washington, and is planned to be expanded to 70 cities
within the next two years.
Applied Power Company (APC)
In January 2001, IDACORP sold APC, a manufacturer, supplier and
distributor of solar photovoltaic systems. IPC had acquired APC
in 1996, and transferred ownership (at book value) to IDACORP on
January 1, 2000. APC was sold at approximately its book value.
IDACORP Financial Services (IFS)
IFS invests primarily in affordable housing projects, which
provide a return primarily by reducing federal income taxes
through tax credits and tax depreciation benefits. In 2000, IFS
expanded its portfolio to include historic rehabilitation projects
such as the El Cortez Hotel in San Diego, California and the
Empire Building in Boise. In January 2000, ownership of IFS was
transferred (at book value) from IPC to IDACORP.
IDACORP Services
IDACORP Services offers a variety of products and services to
residential and business customers. These offerings include: home
security monitoring, carbon monoxide detection, and home surge
protection devices, satellite dish products and services, payment
protection and appliance maintenance.
RESEARCH AND DEVELOPMENT
IdaTech owns several patents on 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. In 2000, IdaTech spent
approximately $1.3 million for research and development of fuel
cell technology.
As an active member of the NEEA, 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 2000, $1.6 million was expended on energy-
efficiency programs.
During 2000, IPC spent approximately $0.1 million on research and
development through membership in Electric Power Research
Institute (EPRI). EPRI creates science technology solutions for
the global energy and energy service. Some of the subjects of
EPRI projects include: power quality, electric transportation
systems, EMF assessment/risk management and air quality issues.
CONSTRUCTION PROGRAM
IDACORP's construction and acquisition program for 2001-2005
(excluding allowances for funds used during construction) is
presently estimated to require cash funds of approximately $716
million as follows:
2001 2002-2005
(Millions of Dollars)
IPC Utility:
Generating facilities
Hydro $ 17.5 $ 67.9
Thermal 9.3 39.4
Total generating facilities 26.8 107.3
Transmission lines and substations 21.0 91.4
Distribution lines and substations 56.5 206.9
General 20.4 98.2
Total IPC cash construction 124.7 503.8
Energy marketing 7.2 7.4
Other 46.0 204.4
Total cash construction
expenditures $ 177.9 715.6
IPC has no nuclear involvement and its future construction plans
do not include development of any nuclear generation. IPC's
capital expenditures are primarily for maintaining current
infrastructures and meeting anticipated electricity demands.
Various options that may be available to meet the future energy
requirements of its customers including efficiency improvements on
IPC's generation, transmission and distribution systems and
purchased power and exchange agreements with other utilities or
other power suppliers. IPC will pursue the projects that best
meet its future energy needs.
FINANCING PROGRAM
The Company's five-year estimate of capital requirements and
sources of capital are outlined in the following table:
Idaho Power
IDACORP,Inc. * Company
2001 2002-2005 2001 2002-2005
(Millions of Dollars)
Capital Requirements:
Net cash construction
expenditure $ 124.7 $ 503.8 $ 124.7 $ 503.8
Other cash
expenditures 53.2 211.8 - -
Total $ 177.9 715.6 124.7 503.8
Sources of Capital:
Internal generation $ 177.9 640.3 124.7 428.1
Short-term bank loans
- net - 36.4 - 97.4
Other debt issued - 78.0 - (6.7)
Other - (39.1) - (15.0)
Total $ 177.9 715.6 124.7 503.8
*includes IPC
Capital expenditures are necessary to fund projects contributing
to the Company's earnings growth.
The above 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, 2000, net earnings were 7.53 times.
Additional preferred stock may be issued when earnings for twelve
consecutive months within the preceding fifteen months are at
least equal to 1.75 times the aggregate annual interest
requirements on all debt securities and dividend requirements on
preferred stock. At December 31, 2000, the actual preferred
dividend earnings coverage was 3.98 times. If the dividends on
the shares of Auction Preferred Stock were to reach the maximum
allowed, the preferred dividend earnings coverage would be 3.05
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 4,656 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 Nameplate
Operating Capacity License
Project Capacity kW 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 (a)
C J Strike 89,000 82,800 2000 (a)
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) 706,667 709,617
Valmy (coal-fired) 260,650 260,650
Boardman (coal-fired) 55,200 56,050
(a)Renewed on a year-to-year basis; application for relicense is
pending.
At December 31, 2000, the composite average ages of the principal
parts of IPC's system, based on dollar investment, were:
production plant, 20 years; transmission system and substations,
20 years; and distribution lines and substations, 15 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 it is in the public interest for IPC to continue to hold the
federal licenses.
IPC is actively pursuing new licenses for 10 of its 17
hydroelectric projects from the FERC. This process could take
anywhere from eight to 15 years, depending on environmental issues
and political processes.
The most significant relicensing will be the Hells Canyon Complex,
which provides over half of IPC's generation capacity. Presently,
IPC is developing study plans within the framework of a
collaborative team made up of individuals representing state and
federal agencies, businesses, environmental, tribal, customer,
local government and local landowner interests. IPC expects to
file the new license application in July 2003.
Shoshone Falls, Upper Salmon Falls, Lower Salmon Falls and Bliss
hydroelectric projects are awaiting an Environmental Impact
Statement (EIS) from the federal government, which is necessary
prior to license issuance. IPC completed 64 Additional
Information Requests (AIRs) from the agencies and non-governmental
organizations in early 2000, which combined with recently filed,
final recommendations, terms and conditions, will be used by the
FERC to produce a draft EIS for these projects in May 2001.
IPC filed its application for a new license for the C J Strike
project in November 1998. Similarly, 21 AIRs were issued on this
project as well and the FERC has noticed that this project is
Ready for Environmental Analysis which gives the agencies and
interested parties 60 days to provide their final recommendations,
terms and conditions for this project. A draft EIS is expected by
August 2001.
The Upper and Lower Malad projects, scheduled for a July 2002 new
license application, are nearing completion of field studies and
reporting should be complete in early 2001.
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 12 operating hydroelectric plants
with a total generating capacity of 72 MW.
ITEM 3. LEGAL PROCEEDINGS
None
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None
EXECUTIVE OFFICERS OF THE REGISTRANT
The names, ages and positions of all of the executive officers of
IDACORP, Inc. are listed below along with their business
experience during the past five years. 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*
Jan B. Packwood, 57 Appointed May 30, 1999. Mr.
President and Chief Packwood was President and Chief
Executive Officer Operating Officer from February 2,
1998 to May 30, 1999.
J. LaMont Keen, 48 Appointed May 5, 1999. Mr. Keen was
Senior Vice President, Senior Vice President-Administration,
Administration and Chief Chief Financial Officer and Treasurer
Financial Officer from March 15, 1999 to May 5, 1999,
and Vice President, Chief Financial
Officer and Treasurer from February
2, 1998 to March 15, 1999.
Richard Riazzi, 46 Appointed March 15, 1999. Mr. Riazzi
Senior Vice President, was Vice President - Marketing and
Generation and Marketing Sales from January 14, 1999 to March
15, 1999.
Darrel T. Anderson, 42 Appointed May 5, 1999.
Vice President-Finance
and Treasurer
Robert W. Stahman, 56 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.
EXECUTIVE OFFICERS OF THE REGISTRANT
The names, ages and positions of all of the executive officers of
Idaho Power Company are listed below along with their business
experience during the past five years. 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.
Idaho Power Company
Name, Age and Position Business Experience During Past Five (5) Years
Jan B. Packwood, 57 Appointed May 30, 1999. Mr. Packwood
President and Chief was President and Chief Operating
Executive Officer Officer from September 1, 1997 to May
30, 1999, Executive Vice President
from July 11, 1996 to September 1,
1997, and Vice President-Power Supply
prior to July 11, 1996.
J. LaMont Keen, 48 Appointed May 5, 1999. Mr. Keen was
Senior Vice President - Senior Vice President-Administration,
Administration and Chief Chief Financial Officer and Treasurer
Financial Officer from March 15, 1999 to May 5, 1999,
Vice President, Chief Financial
Officer and Treasurer from March 14,
1996 to March 15, 1999 and Vice
President and Chief Financial Officer
prior to March 14, 1996.
James C. Miller, 46 Appointed November 18, 1999. Mr.
Senior Vice President - Miller was Vice President -
Delivery Generation from July 10, 1997 to
November 18, 1999 and was General
Manager - Generation prior to July
10, 1997.
Richard Riazzi, 46 Appointed March 15, 1999. Mr. Riazzi
Senior Vice President - was Vice President - Marketing and
Generation and Marketing Sales from January 9, 1997 to March
15, 1999. Mr. Riazzi was Vice
President, Corporate Marketing (1995-
1996) for Equitable Resources, Inc.
Darrel T. Anderson, 42 Appointed May 5, 1999. Mr. Anderson
Vice President - Finance was corporate controller from January
and Treasurer 25, 1999 to May 5, 1999, Executive
Vice President of Finance and
Operations at Applied Power Corp.
from June 5, 1998 to January 25,
1999, and corporate controller from
February 26, 1996 to June 5, 1998.
Mr. Anderson was Senior Manager of
Audit Services for Deloitte & Touche
LLP prior to February 26, 1996.
John P. Prescott, 44 Appointed November 18, 1999. Mr.
Vice President - Prescott was Vice President of
Generation Business Development for IDACORP
Technologies, Inc. from August 1999
to November 18, 1999, and President
and Treasurer of Stellar Dynamics
from October 5, 1995 to August 1999.
Bryan A.B. Kearney, 38 Appointed November 18, 1999. Mr.
Vice President and Chief Kearney was Vice President and Chief
Information Officer Technology Officer at Bear Creek Corp
(1998-1999), Chief Information
Officer for Shasta County, California
(1996-1998), and Director of
Information Systems and Services for
the City of Fort Worth, Texas (1994-
1995).
Cliff N. Olson, 51 Appointed July 11, 1991.
Vice President -
Corporate Services
Robert W. Stahman, 56 Appointed July 13, 1989.
Vice President - General
Counsel and Secretary
Marlene K. Williams, 48 Appointed May 5, 1999. Ms. Williams
Vice President - Human was Director of Human Resources at
Resources Arizona Public Service prior to May
5, 1999.
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, 2000, there
were 21,886 holders of record and the year-end stock price was
$49.06 per share.
The outstanding shares of Idaho Power Company common stock ($2.50
par value) are held by IDACORP, Inc. and are not traded. IDACORP,
Inc. became the holding company of Idaho Power Company on October
1, 1998.
The following table shows the reported high and low sales price
and dividends paid for the years 2000 and 1999 as reported by the
Wall Street Journal as composite tape transactions.
2000 Quarters
Common Stock, without par
value: 1st 2nd 3rd 4th
High $53.00 $37.00 $48.69 $51.81
Low 25.94 31.00 32.38 43.38
Dividends paid per
share (cents) 46.5 46.5 46.5 46.5
______________________________
1999 Quarters
Common Stock, without par
value: 1st 2nd 3rd 4th
High $36.50 $33.63 $32.00 $31.25
Low 29.25 29.50 29.19 26.00
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.
For the Years Ended
December 31, 2000 1999 1998 1997 1996
Operating revenues $1,019,353 $ 731,152 $ 795,087 $ 627,724 $ 598,065
Income from operations 261,663 199,050 193,423 191,746 193,768
Net income 139,883 91,349 89,176 87,098 83,155
Earnings per average
share outstanding
(basic and diluted) 3.72 2.43 2.37 2.32 2.21
Dividends declared per
share 1.86 1.86 1.86 1.86 1.86
At December 31,
Total long-term debt* 864,114 821,558 815,937 746,142 769,810
Total assets 4,639,258 2,640,371 2,456,819 2,451,816 2,328,738
*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)
IDAHO POWER COMPANY
For the Years Ended 2000 1999 1998 1997 1996
December 31,
Operating revenues $ 835,662 $ 658,336 $ 756,410 $ 605,183 $ 578,445
Income from operations 169,636 172,458 180,584 180,731 187,171
Net income 131,559 97,528 95,919 92,274 90,618
At December 31,
Total long-term debt* 808,977 821,558 815,937 746,142 769,810
Total assets 4,295,098 2,559,374 2,421,790 2,451,816 2,328,738
Utility Customer Data:
General business
customers 393,831 384,421 373,730 363,085 352,487
Average kWh per customer 37,068 36,379 36,368 37,080 37,627
Average rate per kWh (cents) 3.87 3.75 3.85 3.63 3.71
*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.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
INTRODUCTION
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),
and several other entities.
IPC is an electric utility with a service territory covering over
20,000 square miles, primarily in southern Idaho, and eastern
Oregon. IPC also conducts electricity marketing and trading
operations, and is the parent of Idaho Energy Resources Co., a
joint venturer in Bridger Coal Company, which supplies coal to
IPC's Jim Bridger generating plant.
IDACORP's other significant operating subsidiaries are:
IDACORP Energy Services - natural gas marketing
Ida-West Energy - independent power projects development and
management
IdaTech - developer of integrated fuel cell systems
IDACORP Financial Services - affordable housing and other real
estate investments
Rocky Mountain Communications- commercial and residential
Internet service provider
IDACOMM - provider of telecommunications services
IDACORP Services - energy related products and services
Applied Power Company - supplier of photovoltaic systems (sold
January 2001).
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,
2000, 1999 and 1998. In our discussion we explain, by operating
segment, 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, any 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);
the current energy situation in the western United States;
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;
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
In this section we discuss our earnings and the factors that
affected them, beginning with a general overview and then
discussing results for each of our operating segments.
Earnings per share of
common stock
2000 1999 1998
Utility operations $ 1.97 $ 2.00 $ 2.13
Energy marketing 1.58 0.34 0.14
Other 0.17 0.09 0.10
Total earnings per
share $ 3.72 $ 2.43 $ 2.37
Return on year-end
common equity 17.0% 12.1% 12.2%
The primary factor contributing to the increases in earnings per
share (EPS) from 1999 to 2000 and from 1998 to 1999 is favorable
energy marketing results. Our net income from energy marketing
increased $47 million in 2000 and $8 million in 1999 due to a
combination of factors, including increased price volatility in
the energy markets, and increased trading volumes over a larger
geographic area.
The decrease in EPS from utility operations from 1999 to 2000 is
predominantly the result of increased net power supply costs, due
to a decline in hydroelectric generating conditions and increased
market prices for purchased power. These cost increases are
partially offset by increased general business revenue resulting
from rate increases, customer growth and weather conditions.
EPS from utility operations was less in 1999 compared to 1998 due
primarily to increased costs at our coal-fired generations plant
and payroll and consulting expenses.
Our EPS from other operations increased in 2000 compared to 1999,
predominantly because of the gain recorded on the sale in March
2000 of the Hermiston Power Project. This gain was partially
offset by losses related to newly acquired subsidiaries.
UTILITY OPERATIONS
This section discusses IPC's utility operations, which are subject
to regulation by, among others, the state public utility
commissions of Idaho, Oregon, and Nevada, and by the Federal
Energy Regulatory Commission. Before we discuss the changes in
income from our utility operations, we'll describe these
operations to help you understand them and the relationship
between the financial statement line items.
IPC owns and operate 17 hydroelectric power plants and shares
ownership in three coal-fired generating plants. The following
table presents IPC's system generation for the last three years:
MWhs (in thousands) Percent of total
generation
2000 1999 1998 2000 1999 1998
Hydroelectric 8,500 10,652 11,135 52% 59% 62%
Thermal 7,701 7,266 6,925 48 41 38
Total system
generation 16,201 17,918 18,060 100% 100% 100%
Hydro generation was seven percent below normal conditions in
2000, 17 percent above normal in 1999 and 22 percent above normal
in 1998.
Because of its reliance on hydroelectric generation, IPC's
generation operations can be significantly affected by the
weather. The availability of inexpensive hydroelectric power
depends on snowpack in the mountains above IPC's hydro facilities,
precipitation and other weather and streamflow management
considerations. When hydroelectric generation decreases and
customer demand increases, as it has from 1998 to 2000, we must
increase our reliance on more expensive thermal generation and
purchased power.
The rates we charge to our general business customers are
determined by the various regulatory authorities. Approximately
95 percent of our general business revenue and sales come from
customers in the state of Idaho. The rates we charge these
customers, (except for customers with special contracts) are
adjusted annually by a power cost adjustment (PCA) mechanism. The
PCA adjusts rates to reflect the changes in costs incurred by IPC
to supply power. Throughout the year, we compare our actual power
supply costs to the amounts we are recovering in rates. Most, but
not all, of this difference is deferred and included in the
calculation of rates for future years.
The primary influences on electricity sales are weather and
economic conditions. Generally, extreme temperatures increase
sales to customers, who use electricity for cooling and heating,
and moderate temperatures decrease sales. Precipitation levels
during the growing season affect sales to customers who use
electricity to operate irrigation pumps. Increased precipitation
reduces electricity usage by these customers.
Strong overall economic conditions in our utility service
territory have resulted in general business customer growth, with
2.4 percent, 2.9 percent and 2.9 percent increases in average
customers served in 2000, 1999, and 1998 respectively.
General Business Revenue
The following table presents IPC's general business revenues and
volumes for the last three years:
Revenues Volumes
(in thousands of dollars) (in thousands of MWh)
2000 1999 1998 2000 1999 1998
Residential $225,336 $213,547 $211,445 4,393 4,200 4,090
Commercial (less
than 1000 kW demand) 129,816 120,846 118,375 3,375 3,164 2,997
Industrial (greater
than 1000 kW demand) 133,171 117,366 124,237 4,808 4,666 4,788
Irrigation 74,827 62,166 58,639 1,993 1,706 1,466
Public Highway and
Street 2,207 2,223 2,160 29 30 28
Total $565,357 $516,148 $514,856 14,598 13,766 13,369
As mentioned above, our general business revenue is dependent on
many factors, including the number of customers we serve, the
rates we charge, and weather conditions.
2000 vs. 1999
The 9.5 percent increase in general business revenues is due to
the following factors:
Increased average rates, resulting from the PCA and special-
contract customers, increased revenues $17 million. We discuss the
PCA in more detail below in "Regulatory Issues - Power Cost
Adjustment";
Increased usage per customer, resulting from weather conditions
and other factors, increased revenues $26 million. Decreased
precipitation during the growing season increased sales to
irrigation customers, and hotter summer and colder winter
temperatures increased sales to the other customer classes;
Our average number of customers increased 2.7 percent over
1999, increasing revenue $6 million.
1999 vs. 1998
In 1999, general business revenue was only marginally higher than
1998. The following factors influenced general business revenue:
A 2.9 percent increase in general business customers increased
revenue $7 million;
Drier weather conditions and other factors affecting usage
increased revenue $12 million;
Decreased average rates, resulting from the PCA, decreased
revenue $17 million.
Off-system sales
Off-system sales consist primarily of long-term sales contracts
and opportunity sales of surplus system energy.
$ (in thousands) MWh (in thousands) Revenue per MWh
2000 1999 1998 2000 1999 1998 2000 1999 1998
$229,986 $119,785 $214,418 4,529 5,924 7,907 $50.78 $20.22 $27.12
2000 vs. 1999
Off-system sales increased due predominantly to significant
increases in prices for surplus system energy, which increased our
average revenue per MWh by over 150 percent. A 24 percent
decrease in volumes of electricity sold, due to decreased
availability, partially offset the increase in market prices.
1999 vs. 1998
Off system sales decreased due principally to two factors, a 25
percent decrease in volumes sold and a 25 percent decrease in
price per MWh.
Power Supply
The Power supply components of income from operations include off-
system sales (described and analyzed above) and purchased power,
fuel and PCA expenses (analyzed below).
The impact of the changes in net power supply costs was an
increase in net power supply expense of $69 million in 2000 and a
decrease of $6 million in 1999. The PCA adjustment is not
designed to fully mitigate the effect of fluctuations in net power
supply costs, and is applicable only to Idaho customers.
Purchased power
$ (in thousands) MWh (in thousands) Cost per MWh
2000 1999 1998 2000 1999 1998 2000 1999 1998
$398,649 $106,344 $185,271 4,311 3,127 4,707 $92.47 $34.01 $39.36
2000 vs. 1999
Purchased power expenses increased $292 million in 2000 due to
major increases in prices in the energy markets, and to increased
volumes purchased. The increase in volumes was necessitated by
decreased generation at our hydroelectric plants and increased
customer demand.
1999 vs. 1998
Purchased power expenses decreased $79 million in 1999.
Contributing to these results are a number of operational factors,
including changing hydro availability, system load and fluctuating
wholesale market conditions.
Fuel expense
$ (in thousands) Thermal MWh generated
(in thousands)
2000 1999 1998 2000 1999 1998
$94,215 $86,617 $86,237 7,701 7,266 6,925
2000 vs. 1999
Fuel expenses increased by $8 million in 2000, due primarily to
increased generation at our coal-fired plants, necessitated by
decreased generation at our hydroelectric plants and increased
customer demand.
1999 vs. 1998
Fuel expenses were essentially unchanged. Increases in generation
were offset by decreased average coal prices.
Power Cost Adjustment
The PCA component of expenses is related to the Company's PCA
regulatory mechanism. The PCA mechanism increases expenses when
power supply costs are below forecast, and decreases expenses when
power supply costs are above forecast. We discuss the PCA in more
detail in "Regulatory Issues - Power Cost Adjustment."
2000 vs. 1999
The PCA expense was a credit of $121 million in 2000, due
predominantly to the considerable increases in purchased power
costs not anticipated in our 2000-2001 rate year forecast. In
1999, actual power supply costs were near forecast, causing the
PCA component of expense to be minimal.
1999 vs. 1998
The PCA decreased $22 million in 1999, due to 1999's power supply
costs being near forecast, while 1998 costs were below forecast.
Other Expenses
2000 vs. 1999
Other operations and maintenance expenses in 2000 were
substantially unchanged from 1999. Decreased pension expenses
were offset by increased distribution line maintenance and general
expenses. Depreciation expenses increased $2 million, primarily
due to plant additions.
1999 vs. 1998
Other operations and maintenance expenses increased $6 million in
1999. The increase was principally due to increased operating
expenses at our coal-fired generation plants, and payroll and
consulting expenses. Depreciation expenses increased $3 million,
due primarily to plant additions.
ENERGY MARKETING
To compete as an energy provider of choice, we have built a
trading operation that participates in the electricity, natural
gas and other related markets from our offices in Boise, Idaho and
Houston, Texas. Our energy marketing and trading strategy has
produced increasingly positive results over the last four years.
Our natural gas marketing capability continues to expand as the
electricity and natural gas markets move toward convergence, and
our electricity marketing efforts have resulted in volume and
income increases each year since inception of the strategy.
When buying and selling energy, the high volatility of energy
prices can have significant negative impact on profitability if
not appropriately managed. Also, counterparty creditworthiness is
key to ensuring that transactions entered into withstand dramatic
market fluctuations. To manage the risks inherent in the energy
commodity industry while implementing our business strategy, our
Risk Management Committee, comprised of Company officers, oversees
the risk management program as defined in our risk management
policy. The program is intended to manage the impact to earnings
caused by the volatility of energy prices by mitigating commodity
price risk, credit risk, and other risks related to the energy
commodity business. We discuss some of these risks later in
"Market Risk."
In August 2000 the IPUC approved our application to move our
nonutility electricity marketing activity to another IDACORP
subsidiary, IDACORP Energy. We expect to have FERC approval by
early April 2001. These non-operating transactions do not involve
sales from IPC's resources and are not related to system
reliability.
Operating Revenues
2000 vs. 1999
Energy marketing revenues increased $114 million in 2000 due
primarily to increased prices in the energy markets and increased
marketing activity. The market conditions in 2000 were something
of an anomaly and as such, we do not anticipate that revenues will
continue to grow at the rate seen in 2000. We anticipate our
marketing revenues to grow in relation to the base 1999 revenues.
1999 vs. 1998
Energy marketing revenues increased $21 million in 1999 due
primarily to increased energy marketing activities.
Operating Expenses
2000 vs. 1999
Energy marketing expenses increased $41 million in 2000 due
primarily to increased administrative expenses related to the
increased marketing activities. This includes increased credit
reserves to reflect, in part, the increased risk associated with
transactions with the California Power Exchange and Independent
System Operator. We have approximately $48 million of receivables
from these entities and have set up reserves in accordance with
our credit policies reflective of the increased credit risk in
these markets.
The Risk Management Policy defines market risk limits within which
trading must be contained. Also, included is an extensive credit
policy within which each counterparty is evaluated for financial
strength and assigned a credit limit. Credit exposure with each
counterparty is measured daily as well as the credit exposure of
the entire portfolio. Our strategy is to diversify credit risk
across counterparties and to set up appropriate credit reserves to
protect against the potential credit losses in the portfolio.
1999 vs. 1998
Energy marketing expenses increased $7 million in 1999 due
primarily to increased energy marketing activities.
OTHER OPERATIONS
Other operations include the results of operations of our
diversified subsidiaries, including Ida-West Energy Company;
IdaTech, LLC; Applied Power Company (APC); IDACORP Financial
Services; IDACORP Services Co.; IDACOMM, Inc.; and Rocky Mountain
Communications, Inc. (RMCI).
Revenues
2000 vs. 1999
Other diversified operating revenues decreased $5 million in 2000
due primarily to a reduction in sales made by APC.
1999 vs. 1998
Other diversified revenues increased $14 million in 1999 due
primarily to revenues of businesses acquired by APC in 1998 and
1999.
Expenses
2000 vs. 1999
Other diversified operating expenses increased $4 million in 2000
due primarily to the operations of RMCI, acquired in August 2000,
and increased activities at IdaTech, our fuel-cell technology
development subsidiary, offset by a reduction in expenses at APC.
1999 vs. 1998
Other diversified operating expenses increased $13 million in 1999
due primarily to expense of businesses acquired by APC in 1998 and
1999.
Other Income
2000 vs. 1999
Other income increased $11 million in 2000 due primarily to the
sale of our interest in the Hermiston Power Project, a 536-MW, gas-
fired cogeneration project to be located near Hermiston, Oregon.
Ida-West Energy Company, a wholly owned subsidiary of IDACORP, was
responsible for managing all permitting and development activities
relating to the project since its inception in 1993. We recorded
a pre-tax gain of $14 million on this transaction.
LIQUIDITY AND CAPITAL RESOURCES
Cash Flow
Our net cash generated from operations totaled $534 million for
the three-year period 1998-2000. After deducting common dividends
of $210 million, net cash generation from operations provided
approximately $324 million for our construction program and other
capital requirements. Internal cash generation after dividends
provided 42 percent of our total capital requirements in 2000, 114
percent in 1999, and 95 percent in 1998. Operating cash flows
declined in 2000, predominantly due to the growth in our PCA
regulatory asset balance, reflecting increased power supply
expenditures that we have not yet recovered through PCA rate
adjustments.
We forecast that internal cash generation after dividends will
provide approximately 101 percent of total capital requirements in
2001 and 109 percent during the four-year period 2002-2005. We
expect to continue financing our utility construction program and
other capital requirements with both internally generated funds
and, to the extent necessary, externally financed capital.
Principal amounts of long-term debt maturing in the next five
years are as follows (in millions of dollars):
2001 2002 2003 2004 2005
Utility $30.1 $27.1 $80.1 $50.1 $60.1
Other 9.7 9.5 9.2 9.3 8.3
At January 1, 2001, IPC had regulatory authority to incur up to
$200 million of short-term indebtedness. At December 31, 2000,
IPC's short-term borrowing totaled $60 million compared to $20
million at December 31, 1999, and $39 million at December 31,
1998.
We have credit facilities established at both IPC and IDACORP.
IPC has a $120 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. Commercial
paper may be issued subject to the regulatory maximum, and is
supported by bank lines of credit of an equal amount.
IDACORP has separately established a $50 million three-year credit
facility that expires in December 2001, and a $100 million 364-day
credit facility that expired in February 2001. We have
established a new 364-day credit facility for up to $375 million
to help support our unregulated operations. Under these
facilities we 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 the amounts supported by the bank credit
facilities. (See Note 7 of "Notes to Consolidated Financial
Statements"). At December 31, 2000, IDACORP's short-term
borrowing totaled $61 million.
Construction Program
Our consolidated cash construction expenditures totaled $140
million in 2000, $111 million in 1999, and $89 million in 1998.
Approximately 29 percent of these expenditures were for generation
facilities, 21 percent for transmission facilities, 36 percent for
distribution facilities, and 14 percent for general plant and
equipment.
We estimate that our cash construction and acquisition programs
will require the following amounts over the next five years.
These estimates are subject to revision in light of changing
economic, regulatory, environmental, and conservation factors.
2001 2002-2005
(In millions of $)
Utility $124.7 $503.8
Energy marketing 7.2 7.4
Other 46.0 204.4
Total $177.9 $715.6
Financing Program
Our consolidated capital structure fluctuated slightly during the
three-year period, with common equity ending at 46 percent,
preferred stock (of IPC) 6 percent, and long-term debt 48 percent
at December 31, 2000.
IDACORP, Inc. currently has a $300 million shelf registration
statement that can be used for the issuance of unsecured debt
securities and preferred or common stock. At December 31, 2000,
none had been issued.
In March 2000 IPC filed a $200 million shelf registration
statement that can be used for both first mortgage bonds
(including medium-term notes), preferred stock and unsecured debt.
In December 2000, $80 million of Secured Medium Term Notes were
issued by IPC. Proceeds from this issuance were used in January
2001 for the early redemption of $75 million of First Mortgage
Bonds originally due in 2021. At December 31, 2000, $120 million
of the total remained to be issued.
In April 2000, at our request, the American Falls Reservoir
District issued its American Falls Refunding Replacement Dam
Bonds, Series 2000. Proceeds from issuance of these bonds, in the
aggregate amount of $19.9 million, were used to refund the same
amount of bonds dated May 1, 1990. IPC has guaranteed repayment
of these bonds.
In May 2000 $4.4 million of tax-exempt Pollution Control Revenue
Refunding Bonds were issued by Port of Morrow, Oregon. Proceeds
were used to refund in August 2000 the same amount of Pollution
control Revenue Bonds, Series 1978.
In November 1999 IPC issued $80 million of Secured Medium Term
Notes. The proceeds from this issuance were used in January 2000
to redeem at maturity $80 million of First Mortgage Bonds.
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.
CURRENT ISSUES
In this section we address a number of other issues that affect or
could affect our operations.
Western Electricity Markets and California Energy Situation
Our utility operations are being affected by the electricity
market conditions in the western United States. The tremendous
increase in prices for purchased power, along with increasing
demand and reduced hydroelectric generation, have combined to
produce substantial increases in our costs to supply power.
The current mountain snowpack above Brownlee Reservoir, our main
storage pool for our Hells Canyon hydro facilities, was at 55
percent of normal in February 2001. This indicates that our
hydroelectric generation could be appreciably diminished in 2001.
In May 2001, we will implement the annual PCA adjustment in Idaho
to recover up to 90% of our costs to supply power in the Idaho
jurisdiction. The cost recovery mechanism is based on the
forecast for the May 2001-May 2002 period and a true-up for the
preceding year. Because the resulting rate increases are expected
to be large, we are exploring an alternative method of cost
recovery with the Idaho Public Utilities Commission and the
legislature. This method, if approved and implemented, would
enable us to recover the costs up front but spread the impact on
our customers out over a longer period of time.
We are also proposing a number of programs to decrease our
reliance on expensive wholesale power. The programs are designed
to reduce overall energy usage, decrease peak-demand levels and
increase generation within our service territory.
With regard to our non-utility energy trading in the state of
California, IPC in January 1999 entered into a Participation
Agreement with the California Power Exchange (CalPX), a California
non-profit public benefit corporation. The CalPX operates a
wholesale electricity market in California by acting as a
clearinghouse through which electricity is bought and sold.
Pursuant to the Participation Agreement, IPC could sell power to
the CalPX under the terms and conditions of the CalPX Tariff.
On January 18, 2001, the CalPX sent us an invoice for $2.2 million
- - a "default share invoice" - as a result of an alleged Southern
California Edison (SCE) payment default of $214.5 million for
power purchases. We made this payment. On January 24, 2001, we
terminated our Participation Agreement with the CalPX. On
February 8, 2001, the CalPX sent a further default share invoice
for $5.2 million, due February 20, 2001, as a result of alleged
payment defaults by SCE and Pacific Gas and Electric Company
(PG&E), and others. However, the CalPX owes us $11.3 million for
power sold to the CalPX in November and December 2000. We did not
pay the February 8 invoice.
The CalPX allocated the defaults of, among others, SCE and PG&E to
the remaining participants based upon the level of trading
activity of each participant during the preceding three-month
period. IPC believes that the default invoices were not proper
and that it owes no further amounts to the CalPX. IPC intends to
pursue all available remedies in its efforts to collect amounts
owed to it by the CalPX.
In addition to the amounts due us from the CalPX, IPC is currently
owed approximately $36.5 million from the Cal ISO for sales in November
and December 2000.
On February 20, we filed a petition with FERC to intervene in a
proceeding which requests the FERC to suspend the use of the CalPX
charge back methodology and provides for further FERC oversight in
the CalPX's implementation of its default mitigation procedures.
Also a preliminary injunction has been granted by a Federal Judge
in the Federal District Court for the Central District of
California enjoining the CalPX from declaring any CalPX
participant in default under the terms of the CalPX Tariff. On March
9,2001, the CalPX filed for Chapter 11 protection with the U.S.
Bankruptcy Court, Central District of California.
We are unable to predict the outcome of these situations.
In California, the Company believes that it has credit exposure in
the range of $30-40 million. The Company continues to manage this
exposure in accordance with established credit policies.
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 in mid-May, 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.
Our May 2000 rate adjustment increased Idaho general business
customer rates by 9.5 percent, and resulted from forecasted below-
average hydroelectric generating conditions. Overall, IPC's
annual general business revenues are expected to increase $38
million during the 2000-2001 rate period.
So far in the 2000-2001 rate period actual power supply costs have
been significantly greater than the forecast, due to actual hydrolectric
conditions being below the forecast, and purchased power prices being
significantly above the forecast. To account for these higher-than-
forecasted costs, IPC has recorded a regulatory asset of $120 million
as of December 31, 2000 ($161 million as of January 31, 2001). In
February, 2001 IPC filed an application with the IPUC proposing to
implement a one-year emergency fuel charge due to these extraordinarily
high expenses. The IPUC suspended the proposed effective date of March
26, 2001 to May 1, 2001, to allow for public workshops and hearings to
be held on the matter. The IPUC also ordered IPC to make its annual PCA
filing as soon as possible so that the cases can be filed jointly. IPC
will be making its filing at the end of March 2001. Due to the overall
weakness in the general credit markets across the United States, and
concerns regarding the liquidity of the western energy markets, any
negative indication by regulators regarding the recovery of wholesale
purchased power costs would affect our ability to successfully access the
credit markets.
The May 1999 rate adjustment reduced rates by 9.2 percent. The
decrease was the result of both forecasted above-average
hydroelectric generating conditions and a true-up from the 1998-99
rate period. Overall, the May 1999 rate adjustment decreased
annual general business revenues by $40 million during the 1999-
2000 rate period.
Regulatory Settlement
IPC had a settlement agreement with the IPUC that expired at the
end of 1999. Under the terms of the settlement, when earnings in
our Idaho jurisdiction exceeded an 11.75 percent return on year-
end common equity, we set aside 50 percent of the excess for the
benefit of our Idaho retail customers.
In March 2000 we submitted our 1999 annual earnings sharing
compliance filing to the IPUC. This filing indicated that there
was almost $9.6 million in 1999 earnings and $2.7 million in
unused 1998 reserve balances available for the benefit of our
Idaho customers.
In April 2000 the IPUC ordered that $6.9 million of the revenue
sharing balance be refunded to Idaho customers through rate
reductions effective May 16, 2000 thus reducing the effect of the
PCA on revenues and customer rates. The IPUC also approved IPC's
continuing participation in the Northwest Energy Efficiency
Alliance (NEEA) through 2004, ordering IPC to set aside the
remaining $5.4 million of revenue sharing dollars to fund that
participation.
Demand-Side Management (Conservation) Expenses
IPC requested that the IPUC allow for the recovery of post-1993
DSM expenses and acceleration of the recovery of DSM expenditures
authorized in the last general rate case. The IPUC set a new
amortization period of 12 years instead of the 24-year period
previously established. The order reflects an increase in annual
Idaho retail revenue requirements of $3.1 million for 12 years.
On April 17, 2000, the Idaho Supreme Court affirmed the IPUC
order, after hearing an appeal by a group of industrial customers.
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.
In 1997, the Idaho Legislature appointed a committee to study
restructuring of the electric utility industry. Although the
committee will continue studying a variety of restructuring ideas,
it has not recommended any restructuring legislation and is not
expected to in the foreseeable future.
In 1999, the Oregon legislature passed legislation restructuring
the electric utility industry, but exempted IPC's service
territory.
Integrated Resource Plan (IRP)
Every two years, IPC is required to file with the IPUC and OPUC an
IRP, a comprehensive look at IPC's present and future demands for
electricity and plan for meeting that demand. The 2000 IRP
identifies a potential electricity shortfall within our utility
service territory by mid-2004. The plan projects a 250-MW
resource need in 2004 to satisfy energy demand during IPC's peak
periods. Prior to 2004, the IRP calls for IPC to increase
purchases from the Northwest energy markets to meet short-term
energy needs. IPC anticipates that after 2004, transmission
constraints will not allow it to continue to cover increasing
demand by increasing purchases.
IPC issued a request for proposals (RFP), seeking bids for 250 MW
of additional generation to support the growing demand in IPC's
utility service territory. A proposal by Garnet Energy LLC, a
subsidiary of Ida-West Energy, was selected by IPC. In January
2001 IPC signed an agreement with Garnet to define the conditions
under which the utility will purchase energy produced at the 250-
MW project. Garnet has proposed building the natural gas-fired
turbine facility in Canyon County, Idaho, located in the southwest
part of the state.
Upon completion of negotiations, targeted for May 1, 2001, the
contract will be submitted to the IPUC and OPUC for approval and
determination of how purchase power costs will be recovered
through customers' rates.
Regional Transmission Organizations
In December 1999 the Federal Energy Regulatory Commission, in its
landmark Order 2000, said that all companies with transmission
assets must file to form regional transmission organizations
(RTOs) or explain why they cannot. Order 2000 is a follow up to
orders 888 and 889 issued in 1996, which required transmission
owners to provide non-discriminatory transmission service to third
parties. By encouraging the formation of RTOs, FERC seeks to
further facilitate the formation of liquid wholesale electricity
markets.
In response to FERC Order 2000, IPC and other regional
transmission owners filed in October 2000 a plan to form RTO West,
an independent entity that will operate the transmission grid in
eight western states. RTO West will have its own independent
governing board. The participating transmission owners will retain
ownership of the lines, but will not have a role in operating the
grid.
The FERC filing represents a major portion of the filing necessary
to form RTO West. However, substantial additional filings will be
necessary to include the tariff and integration agreements
associated with the new entity and filings for state approvals. We
expect the FERC filings to be completed by the summer of 2001 and
state filings to be initiated in late 2001 or early 2002.
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, CJ 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, 2000, $27 million of relicensing costs
were included in Construction Work in Progress.
Market Risk
The following discussion summarizes the financial instruments,
derivative instruments and derivative commodity instruments
sensitive to changes in interest rates and commodity prices that
we held at December 31, 2000. We buy and sell 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, forwards, options and swaps as a method of managing the
commodity price risk and optimizing the profitability of our
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,
2000 is immaterial.
Interest Rate Risk Sensitivity
This table presents descriptions of our financial instruments at
December 31, 2000, that are sensitive to changes in interest
rates. We did not hold any interest rate derivative instruments
at December 31, 2000. The majority of our debt is held in fixed
rate securities with embedded call options. We hold $72 million
in variable-rate tax-exempt debt and 11.8 percent of our total
debt is variable in the form of commercial paper. By nature, the
value of our variable rate debt is not sensitive to changes in
interest rates, and the value of our commercial paper borrowings
does 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, 2000,
based on market rates for similar instruments as of that date.
Expected Average
Maturity Date Amount due interest rate
(in millions)
2001 $ 40 6.9%
2002 37 6.8%
2003 89 6.5%
2004 59 7.9%
2005 69 6.0%
Thereafter 539 7.8%
Total $ 833 7.4%
Fair Value $ 861
Commodity Price Risk Sensitivity
This analysis presents the estimated December 2000, 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, forwards,
options and swaps to manage our exposure to commodity price risk
in the electricity and natural gas markets. The objective of our
risk management 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.
High energy prices and volatility of prices exposes our company to
risk of earnings and cash flow fluctuations. The value-at-risk
measure is a tool used by our Risk Management Committee to
understand the earnings and cashflow risks on a daily basis as the
markets change.
The aggregate potential daily loss in earnings from our energy
trading activity is estimated to be $3.9 million at a 95 percent
confidence interval and for a holding period of one business day.
The potential loss in earnings was estimated using an analytic
value-at-risk methodology. This methodology computes value-at-risk
based upon market prices for futures and historical volatilities
as of December 31, 2000. The value-at-risk is understood to be a
forecast and is not guaranteed to occur. The chosen confidence
level and holding period are industry standards. The confidence
level and holding period imply that there is a five percent chance
that the daily loss will exceed $3.9 million. The value at risk
calculation is principally affected by market prices and
volatility of prices. The extreme increases of volatility and
prices in the energy markets in December 2000 are the primary
cause of the increase in our value at risk. The Risk Management
Committee actively manages the risk to keep our trading activities
within trading limits.
Diversified Business Activities
Telecommunication Services
In August 2000, we formed IDACOMM, Inc. to provide
telecommunications services using fiber optic technology. Also,
in August 2000, we acquired a controlling interest in Rocky
Mountain Communications, Inc. (RMCI), a Boise, Idaho-based
Internet service provider. Since the acquisition, IDACORP and RMCI
launched a new service-Velocitus Broadband. Velocitus offers a
wide variety of broadband solutions for businesses and will be
introduced in 69 markets throughout the western United States.
RMCI currently serves more than 25,000 subscribers of traditional
and high-speed Internet access services in both the residential
and business markets.
As part of the acquisition of RMCI, IDACORP's board of directors
approved the repurchase of up to 350,000 shares of outstanding
common stock. These shares will be distributed to RMCI
shareholders, representing partial payment for the acquisition.
The amount and timing of the repurchase depend on market
conditions. As of December 31, 2000, we had repurchased 156,300
shares for this purpose, at a cost of $6.6 million, and
distributed 154,500 shares to RMCI shareholders. Additional
shares were repurchased in January 2001 and are expected to be
distributed in early 2001.
IDACORP Financial
IDACORP Financial, a wholly owned subsidiary of IDACORP, is
expanding its investment portfolio to include projects that
provide historical tax credits. IDACORP Financial recently closed
on a historical tax credit project in San Diego, California, the
El Cortez project, which began to contribute to earnings in the
third quarter of 2000.
IdaTech
In June 2000, IdaTech (formerly Northwest Power Systems), a
majority-owned subsidiary of IDACORP, delivered the first of 110
fuel cell systems to Bonneville Power Administration (BPA). Since
then, five additional units have been delivered. After three
months of field testing, IdaTech also received notice from the BPA
to proceed with the design and production of the first block of 50
"beta" fuel cell systems for testing in 2001.
IdaTech also received Notice of Allowance from the U.S. Patent
Office of all claims in an additional patent on its fuel
processor. This patent covers the process that will help reduce
the cost of the materials used in the hydrogen purification
module. IdaTech demonstrated a natural gas fuel cell system this
summer and continues to work on key alliances to meet the goal of
commercializing fuel cell systems for home applications by 2003,
and small-scale consumer and commercial applications by late 2002.
Applied Power Company (APC)
In January 2001, we sold APC to Schott Corp. APC is a
manufacturer, supplier and distributor of solar photovoltaic
systems. IDACORP originally acquired APC in 1996.
Environmental and Legal Issues
Salmon Recovery Plan
We are continuing to monitor regional efforts to develop 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. This
designation has not had any major effects on our operations.
In September 1991, we voluntarily modified operations at our three-
dam Hells Canyon Complex (HCC) to protect the Fall Chinook
downstream during spawning and juvenile emergence. From its
start, this Fall Chinook Program has provided the Fall Chinook the
high level of protection due an endangered species.
In December 2000, the National Marine Fisheries Service (NMFS)
issued a Final Biological Opinion (BiOp) for operations of the
Federal Columbia River Power System. The BiOp did not call for
changes in the Company's operations for salmon at the HCC.
The NMFS has also developed a draft specifically for operations of
the HCC. The draft BiOp seeks to change existing operations of
the HCC. The NMFS, FERC, and IPC are currently involved in
discussions of the draft BiOp. IPC believes that no changes to
the HCC operations or facilities are justified, and will
vigorously defend this position. However, the Company is unable
to predict what impact, if any, a final NMFS BiOp may have on
operations of the HCC.
The Bureau of Reclamation (BOR) has been seeking, unsuccessfully,
for the last 5 years to acquire additional water in the upper
Snake for fish flow augmentation. While it is likely the BOR will
continue to seek additional water, it is unlikely, absent a
settlement with all Idaho state interests that they will succeed
in their efforts. In connection with water moved in the past, the
Company has been compensated for its losses pursuant to an
agreement with the BPA. If the BOR was successful in its efforts,
the Company would expect compensation.
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.
New Accounting Pronouncements
In June 1998 the Financial Accounting Standards Board issued
Statement of Financial Accounting Standards No. 133 "Accounting
for Derivative Instruments and Hedging Activities." In June 2000,
the FASB issued SFAS No. 138 "Accounting for Certain Derivative
Instruments and Certain Hedging Activities", which amended certain
provisions of SFAS 133. The Derivative Implementation Group, a
task force created by the FASB, is continuing to identify and
resolve implementation questions related to SFAS 133 and SFAS 138.
SFAS 133, as amended by SFAS 138, was effective as of January 1,
2001. As of January 1, 2001 contracts company-wide have been
evaluated based upon the SFAS 133 derivative definition and
requirements. Most of the Company's identified derivatives
consist of energy trading contracts that are currently reported at
fair value under the provisions of Emerging Issues Task Force 98-
10. The remaining derivatives are IPC electricity purchase and
sales contracts that are subject to regulatory processes. As a
result, the adoption of SFAS 133, as amended, did not have a
material effect on the Company's financial position, results of
operations, or cash flows.
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 Risk."
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 31,2000, 1999 and 1998 39
Consolidated Balance Sheets as of December 31, 2000,
1999 and 1998 40-41
Consolidated Statements of Capitalization as of December
31, 2000, 1999 and 1998 42
Consolidated Statements of Cash Flows for the Years Ended
December 31, 2000, 1999 and 1998 43
Consolidated Statements of Retained Earnings and Consolidated
Statements of Comprehensive Income for the Years Ended
December 31, 2000, 1999 and 1998 44
Notes to Consolidated Financial Statements 45-60
Independent Auditors' Report 61
Idaho Power Company
Consolidated Statements of Income for the Years Ended
December 31, 2000, 1999 and 1998 63
Consolidated Balance Sheets as of December 31, 2000, 1999
and 1998 64-65
Consolidated Statements of Capitalization as of December
31, 2000, 1999 and 1998 66
Consolidated Statements of Cash Flows for the Years Ended
December 31, 2000, 1999 and 1998 67
Consolidated Statements of Retained Earnings and Consolidated
Statements of Comprehensive Income for the Years Ended
December 31, 2000, 1999 and 1998 68
Notes to Consolidated Financial Statements 69-72
Independent Auditors' Report 73
Supplemental Financial Information and Financial Statement
Schedules
Supplemental Financial Information (Unaudited) 74
Financial Statement Schedules for the Years Ended December 31,
2000, 1999 and 1998:
Schedule II-Consolidated Valuation and Qualifying Accounts-
IDACORP, Inc. 80
Schedule II-Consolidated Valuation and Qualifying Accounts-Idaho
Power Company. 80
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, meets 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.
Jan B. Packwood J. LaMont Keen Darrel T. Anderson
President and Senior Vice President, Vice President-
Chief Executive Officer Administration and Finance and Treasurer
Chief Financial Officer
IDACORP, Inc.
Consolidated Statements of Income
Year Ended December 31,
2000 1999 1998
(Thousands of Dollars Except for
Per Share Amounts)
OPERATING REVENUES:
Electric Utility:
General business $ 565,357 $ 516,148 $ 514,856
Off system sales 229,986 119,785 214,418
Other revenues 40,319 22,403 27,136
Total electric utility
revenues 835,662 658,336 756,410
Diversified Operations:
Energy marketing 145,400 31,368 10,745
Other 24,004 29,426 15,443
Total diversified
operations 169,404 60,794 26,188
Earnings of
unconsolidated
partnerships, joint
ventures and
subsidiaries 14,287 12,022 12,489
Total operating
revenues 1,019,353 731,152 795,087
OPERATING EXPENSES:
Electric Utility:
Purchased power 398,649 106,344 185,271
Fuel expense 94,215 86,617 86,237
Power cost adjustment (120,688) (502) 21,866
Other operations and
maintenance 193,397 193,867 187,246
Depreciation 80,287 77,833 74,481
Taxes other than income
taxes 20,166 21,719 20,725
Total electric utility
expenses 666,026 485,878 575,826
Diversified Operations:
Energy marketing 50,811 9,684 2,782
Other 40,853 36,540 23,056
Total diversified
operations 91,664 46,224 25,838
Total operating
expenses 757,690 532,102 601,664
OPERATING INCOME 261,663 199,050 193,423
OTHER INCOME:
Allowance for equity
funds used during
construction 2,565 1,667 300
Gain on sale of asset 14,000 - -
Other - net (605) 3,459 5,518
Total other income 15,960 5,126 5,818
INTEREST EXPENSE AND
OTHER:
Interest on long-term
debt 53,356 54,294 52,270
Other interest 9,983 8,681 8,407
Allowance for borrowed
funds used during
construction (2,346) (1,392) (900)
Preferred dividends of
Idaho Power Company 5,929 5,572 5,658
Total interest expense
and other 66,922 67,155 65,435
INCOME BEFORE INCOME
TAXES 210,701 137,021 133,806
INCOME TAXES 70,818 45,672 44,630
NET INCOME $ 139,883 $ 91,349 $ 89,176
AVERAGE COMMON SHARES
OUTSTANDING (000's) 37,556 37,612 37,612
EARNINGS PER SHARE OF
COMMON STOCK (basic
and diluted) $ 3.72 $ 2.43 $ 2.37
The accompanying notes are an integral part of these statements.
IDACORP, Inc.
Consolidated Balance Sheets
December 31,
2000 1999 1998
(Thousands of Dollars)
ASSETS
CURRENT ASSETS:
Cash and cash
equivalents $ 106,795 $ 111,338 $ 22,867
Receivables:
Customer 243,647 98,923 102,671
Allowance for
uncollectible accounts (1,397) (1,397) (1,397)
Employee notes 4,742 4,105 4,510
Other 15,611 12,117 10,702
Energy marketing assets 1,681,554 37,398 -
Accrued unbilled
revenues 44,825 31,994 34,610
Materials and supplies
(at average cost) 29,731 29,611 30,157
Fuel stock (at average
cost) 5,105 9,329 7,096
Prepayments 24,575 16,097 16,042
Regulatory assets
associated with income 8,672 893 2,965
taxes
Total current assets 2,163,860 350,408 230,223
INVESTMENTS AND OTHER
ASSETS 157,068 139,091 124,021
PROPERTY, PLANT AND
EQUIPMENT
Utility plant in service 2,799,874 2,726,026 2,659,441
Accumulated provision
for depreciation (1,142,572) (1,073,722) (1,009,387)
Utility plant in
service - net 1,657,302 1,652,304 1,650,054
Construction work in
progress 136,388 91,637 59,717
Utility plant held for
future use 2,167 1,742 1,738
Other property, net of
accumulated depreciation 9,179 6,928 5,416
Property, plant and
equipment - net 1,805,036 1,752,611 1,716,925
DEFERRED DEBITS:
American Falls and
Milner water rights 31,585 31,585 31,830
Company-owned life
insurance 39,554 40,480 35,149
Regulatory assets
associated with income
taxes 204,880 214,782 201,465
Regulatory assets - PCA 119,905 - -
Regulatory assets -
other 45,750 56,137 67,212
Other 71,620 55,277 49,994
Total deferred debits 513,294 398,261 385,650
TOTAL $4,639,258 $2,640,371 $2,456,819
The accompanying notes are an integral part of these statements.
IDACORP, Inc
Consolidated Balance Sheets
December 31,
2000 1999 1998
(Thousands of Dollars)
LIABILITIES AND
CAPITALIZATION
CURRENT LIABILITIES:
Current maturities of
long-term debt $ 39,774 $ 89,101 $ 6,029
Notes payable 120,600 19,757 38,524
Accounts payable 272,376 145,737 101,975
Energy marketing
liabilities 1,706,501 33,814 -
Taxes accrued 15,631 21,313 24,785
Interest accrued 16,985 19,126 18,365
Deferred income taxes 8,672 893 2,965
Other 28,104 16,696 12,275
Total current
liabilities 2,208,643 346,437 204,918
DEFERRED CREDITS:
Deferred income taxes 460,464 430,468 422,196
Regulatory liabilities
associated with deferred
investment tax credits 66,050 67,433 69,396
Regulatory liabilities
associated with income
taxes 40,230 33,817 28,075
Regulatory liabilities -
PCA - 3,378 5,199
Regulatory liabilities -
other 4,621 3,363 4,161
Other 69,259 75,136 70,572
Total deferred credits 640,624 613,595 599,599
LONG-TERM DEBT 864,114 821,558 815,937
COMMITMENTS AND CONTINGENT
LIABILITIES
PREFERRED STOCK OF IDAHO
POWER COMPANY 105,066 105,811 105,968
COMMON STOCK EQUITY:
Common stock, no par
value (shares authorized
120,000,000; 37,612,351
shares issued) 453,102 451,343 451,564
Retained earnings 370,126 300,093 278,607
Accumulated other
comprehensive income
(loss) (921) 1,534 226
Treasury stock (44,425
shares at cost) (1,496) - -
Total common stock
equity 820,811 752,970 730,397
TOTAL $4,639,258 $2,640,371 $2,456,819
The accompanying notes are an integral part of these statements.
IDACORP, Inc.
Consolidated Statements of Capitalization
December 31,
2000 % 1999 % 1998 %
(Thousands of Dollars)
COMMON STOCK EQUITY:
Common stock $ 453,102 $ 451,343 $ 451,564
Retained earnings 370,126 300,093 278,607
Accumulated other comprehensive
income (loss) (921) 1,534 226
Treasury stock (1,496) - -
Total common stock equity 820,811 46 752,970 45 730,397 44
PREFERRED STOCK OF IDAHO POWER
COMPANY:
4% preferred stock 15,066 15,811 15,968
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 105,066 6 105,811 6 105,968 7
LONG-TERM DEBT:
First mortgage bonds:
8.65% Series due 2000 - 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 60,000 60,000
7.38% Series due 2007 80,000 - -
7.20% Series due 2009 80,000 80,000 -
Maturing 2021 through 2031
with rates ranging
from 7.5% to 9.52% 230,000 230,000 230,000
Total first mortgage bonds 637,000 637,000 557,000
Amount due within one year (30,000) (80,000) -
Net first mortgage bonds 607,000 557,000 557,000
Pollution control revenue
bonds:
7 1/4% Series due 2008 - 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
Variable Rate Series 2000 due
2027 4,360 - -
Total pollution control
revenue bonds 170,460 170,460 170,460
REA notes 1,339 1,415 1,489
Amount due within one year (77) (76) (74)
Net REA notes 1,262 1,339 1,415
American Falls bond guarantee 19,885 19,885 20,130
Milner Dam note guarantee 11,700 11,700 11,700
Unamortized premium/discount -
net (1,330) (1,441) (1,539)
Debt related to investments in
affordable housing with
rates ranging from 6.03% to
8.59% due 2000 to 2011 64,063 71,183 62,103
Amount due within one year (9,697) (9,025) (5,955)
Net affordable housing debt 54,366 62,158 56,148
Other subsidiary debt 771 457 623
Total long-term debt 864,114 48 821,558 49 815,937 49
TOTAL CAPITALIZATION $1,789,991 100 $1,680,339 100 $1,652,302 100
The accompanying notes are an integral part of these statements.
IDACORP, Inc.
Consolidated Statements of Cash Flows
Year Ended December 31,
2000 1999 1998
(Thousands of Dollars)
OPERATING ACTIVITIES:
Net income $ 139,883 $ 91,349 $ 89,176
Adjustments to reconcile net
income to net cash provided
by operating activities:
Unrealized (gains) losses
from energy marketing
activities 28,531 (3,584) -
Gain on sale of asset (14,000) - -
Depreciation and amortization 103,971 95,436 87,143
Deferred taxes and investment
tax credits 46,718 (1,820) (10,182)
Accrued PCA costs (122,353) (891) 21,658
Change in:
Receivables and prepayments (157,182) 2,683 4,883
Accrued unbilled revenues (12,831) 2,616 (1,298)
Materials and supplies and
fuel stock 4,104 (1,687) (925)
Accounts payable 125,704 43,762 (9,963)
Taxes accrued (5,682) (3,472) 489
Other current assets and
liabilities 4,917 5,182 (825)
Other - net (8,145) 1,014 (10,269)
Net cash provided by
operating activities 133,635 230,588 169,887
INVESTING ACTIVITIES:
Additions to property, plant
and equipment (140,302) (110,974) (89,184)
Investments in affordable
housing projects (29,166) (19,554) (19,139)
Proceeds from sale of asset 17,500 - -
Investments in company-owned
life insurance - (5,862) -
Other - net (642) (5,060) 3,206
Net cash used in investing
activities (152,610) (141,450) (105,117)
FINANCING ACTIVITIES:
Proceeds from issuance of:
First mortgage bonds 80,000 80,000 60,000
Long-term debt related to
affordable housing projects 10,021 18,730 20,556
Pollution control revenue
bonds 4,360 - -
Retirement of:
Subsidiary debt (926) (165) (4,316)
Long-term debt related to
affordable housing projects (17,141) (9,650) (4,838)
First mortgage bonds (80,000) - (30,000)
Pollution control revenue
bonds (4,360) - -
Dividends on common stock (69,850) (69,863) (69,868)
Increase (decrease) in short-
term borrowings 100,843 (18,767) (18,992)
Acquisition of treasury stock (8,014) - -
Other - net (501) (952) (1,350)
Net cash provided by (used
in) financing activities 14,432 (667) (48,808)
Net increase (decrease) in cash
and cash equivalents (4,543) 88,471 15,962
Cash and cash equivalents
beginning of period 111,338 22,867 6,905
Cash and cash equivalents at end
of period $ 106,795 $ 111,338 $ 22,867
SUPPLEMENTAL DISCLOSURE OF CASH
FLOW INFORMATION:
Cash paid during the year for:
Income taxes $ 29,830 $ 51,750 $ 55,527
Interest (net of amount
capitalized) $ 61,825 $ 56,295 $ 53,806
The accompanying notes are an integral part of these statements.
IDACORP, Inc.
Consolidated Statements of Retained Earnings
Year Ended December 31,
2000 1999 1998
(Thousands of Dollars)
RETAINED EARNINGS, BEGINNING OF YEAR $300,093 $278,607 $259,299
NET INCOME 139,883 91,349 89,176
Total 439,976 369,956 348,475
COMMON STOCK DIVIDENDS (69,850) (69,863) (69,868)
RETAINED EARNINGS, END OF YEAR $370,126 $300,093 $278,607
The accompanying notes are an integral part of these statements.
Consolidated Statements of Comprehensive Income
Year Ended December 31,
2000 1999 1998
(Thousands of Dollars)
NET INCOME $139,883 $ 91,349 $ 89,176
OTHER COMPREHENSIVE INCOME (LOSS):
Unrealized gains (losses) on
securities (net of tax of
($1,713),$677, and $2,185) (2,335) 1,017 3,385
Minimum pension liability
adjustment (net of tax of
($78),$189 and ($2,054)) (119) 291 (3,159)
TOTAL COMPREHENSIVE INCOME $137,429 $ 92,657 $ 89,402
The accompanying notes are an integral part of these statements
IDACORP, Inc.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Nature of Business
IDACORP, Inc. (IDACORP or the Company) is a holding company whose
principal operating subsidiary is Idaho Power Company (IPC). IPC is
regulated by the FERC and the state regulatory commissions of Idaho,
Oregon, Nevada and Wyoming, and is engaged in the generation,
transmission, distribution, sale and purchase of electric energy.
IPC is the parent of Idaho Energy Resources Co., a joint venturer in
Bridger Coal Company, which supplies coal to IPC's Jim Bridger
generating plant.
IDACORP's other significant subsidiaries are:
IDACORP Energy Services - natural gas marketing
Ida-West Energy - independent power projects development and
management
IdaTech - developer of integrated fuel cell systems
IDACORP Financial Services - affordable housing and other real
estate investments
Rocky Mountain Communications - commercial and residential
Internet service provider
IDACOMM - provider of telecommunications services
IDACORP Services - energy related products and services
Applied Power Company - supplier of photovoltaic systems (sold
January 2001).
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.
Property, Plant and Equipment
The cost of additions to utility 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 property, plant and equipment.
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 2000, 1999 and 1998 were 8.3 percent,
7.8 percent, and 6.0 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.
IPC had a regulatory settlement with the Idaho Public Utilities
Commission (IPUC) that expired in 1999. Under terms of the
settlement, when earnings in the Idaho jurisdiction exceeded an
11.75 percent return on year-end common equity, 50 percent of the
excess was set aside for the benefit of IPC's Idaho retail
customers.
In March 2000 IPC submitted a 1999 annual earnings sharing
compliance filing to the IPUC. This filing indicated that there was
almost $9.6 million in 1999 earnings and $2.7 million in unused 1998
reserve balances available for the benefit of IPC's Idaho customers.
In April 2000 the IPUC ordered that $6.9 million of the revenue
sharing balance be refunded to Idaho customers through rate
reductions effective May 16, 2000. The IPUC also approved IPC's
continuing participation in the Northwest Energy Efficiency Alliance
(NEEA) through 2004, ordering IPC to set aside the remaining $5.4
million of revenue sharing dollars to fund that participation.
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 future annual rate adjustments.
Depreciation
All utility plant in service is depreciated using the straight-line
method at rates approved by regulatory authorities. Annual
depreciation provisions as a percent of average depreciable utility
plant in service approximated 2.94 percent in 2000, 2.94 percent in
1999 and 2.87 percent in 1998.
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 computed using book lives 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.
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.
Management Estimates
The preparation of financial statements in conformity with
accounting principles generally accepted in the United States of
America, 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. Transmission
services may soon be provided by Regional Transmission Organizations
rather than utilities.
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. In 1997, the Idaho Legislature appointed a committee
to study restructuring of the electric utility industry. Although
the committee will continue studying a variety of restructuring
ideas, it has not recommended any restructuring legislation and is
not expected to in the foreseeable future. In 1999, the Oregon
legislature passed legislation restructuring the electric utility
industry, but exempted IPC's service territory. 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 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 2000, 1999 and 1998:
2000 1999 1998
Assets Liabilities Assets Liabilities Assets Liabilities
(Millions of Dollars)
Income taxes $213.6 $ 40.2 $215.7 $ 33.8 $204.4 $ 28.1
Conservation 32.3 - 37.5 - 43.3 -
Employee benefits 3.7 - 4.7 - 5.6 -
PCA deferral and
amortization 119.9 - - 3.4 - 5.2
Other 9.7 4.7 13.9 3.4 18.3 4.1
Deferred investment
tax credits - 66.0 - 67.4 - 69.4
Total $379.2 $110.9 $271.8 $108.0 $271.6 $106.8
At December 31, 2000, IPC had $5.5 million of regulatory assets that
were not earning a return on investment, excluding the $213.6
million that relates to income taxes.
In the event that recovery of costs through rates becomes unlikely
or uncertain, SFAS 71 would no longer apply. If the Company were to
discontinue application of SFAS 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
The Company uses financial instruments such as commodity futures,
forwards, options and swaps to manage exposure to commodity price
risk in the electricity and natural gas markets. The objective of
the Company's risk management program is to mitigate the risk
associated with the purchase and sale of natural gas and electricity
as well as to optimize its energy marketing portfolio. 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 Emerging Issues Task Force (EITF) 98-10,
"Accounting for Contracts Involved in Energy Trading Activities".
EITF 98-10 was adopted effective January 1, 1999 resulting in an
adjustment to net income that was not material.
Energy trading contracts as defined by EITF 98-10 are reported at
fair value on the balance sheet with the resulting gains and losses
reported on the income statement. The fair value of positions
recorded on the balance sheet is dependant on the prices and
volatility of the energy markets. As such, these items on the
balance sheet can fluctuate greatly without large changes in volumes
or positions. Cash flows from energy trading contracts are
recognized in the statement of cash flows as an operating activity.
The following table shows a summary of the notional amounts of the
Company's forward exposure (including both sales and purchases) as
of December 31, 2000 and 1999. The maximum term related to any
forward position is ten years.
December 31,2000 December 31,1999
Gas Electricity Gas Electricity
MMbtu's MWh's MMbtu's MWh's
Total gross
notional volume 190,777 34,453 112,513 10,818
The following table displays the fair values of the Company's energy
marketing assets and liabilities at December 31, 2000 and 1999, and
the average values for the twelve months ended December 31, 2000 (in
thousands of dollars):
Balance at Twelve Months Balance at
December 31,2000 Average Balance December 31,1999
Assets Liabilities Assets Liabilities Assets Liabilities
Gas $ 108,935 $ 115,537 $ 67,263 $ 69,742 $ 8,302 $ 8,220
Electricity 1,572,619 1,590,964 401,956 397,914 29,096 25,594
Total $1,681,554 $1,706,501 $ 469,219 $ 467,656 $ 37,398 $ 33,814
The gain in fair value of energy trading contract positions
(including electricity and natural gas forwards, futures, options
and swaps) included in income before income taxes for the years
ended December 31, 2000 and 1999 were $145.4 million and $31.4
million respectively.
Notional amounts listed above reflect the volume of energy related
to transactions with counterparties, but do not measure exposure to
market or credit risks. The maximum term detailed above also is not
indicative of likely future cash flows as positions may be offset in
the markets at any time to meet risk management guidelines.
Comprehensive Income
Components of the Company's comprehensive income include net income,
unrealized holding gains on marketable securities, 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 issued
Statement of Financial Accounting Standards No. 133 "Accounting for
Derivative Instruments and Hedging Activities." In June 2000, the
FASB issued SFAS No. 138 "Accounting for Certain Derivative
Instruments and Certain Hedging Activities", which amended certain
provisions of SFAS 133. The Derivative Implementation Group, a task
force created by the FASB, is continuing to identify and resolve
implementation questions related to SFAS 133 and SFAS 138.
SFAS 133, as amended by SFAS 138, was effective as of January 1,
2001. As of January 1, 2001 contracts company-wide have been
evaluated based upon the SFAS 133 derivative definition and
requirements. Most of the Company's identified derivatives consist
of energy trading contracts that are currently reported at fair
value under the provisions of Emerging Issues Task Force 98-10. The
remaining derivatives are IPC electricity purchase and sales
contracts that are subject to regulatory processes. As a result,
the adoption of SFAS 133, as amended, did not have a material effect
on the Company's financial position, results of operations, or cash
flows.
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 2000 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 1996 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:
2000 1999 1998
(Thousands of Dollars)
Computed income taxes based
on statutory federal income
tax rate $ 73,746 $ 47,957 $ 46,832
Change in taxes resulting
from:
AFDC (1,719) (1,071) (420)
Investment tax credits (3,083) (3,032) (2,934)
Repair allowance (4,550) (2,800) (2,800)
Settlement of prior years
tax returns 161 (380) (1,965)
State income taxes (net of
federal reduction) 9,793 6,250 7,574
Depreciation 8,243 7,292 5,237
Affordable housing and
historic tax credits (net
of related deferred
taxes) (12,962) (8,934) (6,504)
Preferred dividends of IPC 2,075 1,950 1,980
Other (886) (1,560) (2,370)
Total provision for federal
and state income taxes $ 70,818 $ 45,672 $ 44,630
Effective tax rate 33.6% 33.3% 33.4%
The provision for income taxes consists of the following:
2000 1999 1998
(Thousands of Dollars)
Income taxes currently
payable:
Federal $ 18,984 $ 38,165 $ 45,606
State 5,169 9,327 9,206
Total 24,153 47,492 54,812
Income taxes deferred -
net of amortization:
Federal 40,641 2,174 (8,006)
State 7,407 (2,031) (1,376)
Total 48,048 143 (9,382)
Investment tax credits:
Deferred 1,700 1,069 2,134
Restored (3,083) (3,032) (2,934)
Total (1,383) (1,963) (800)
Total provision for income
taxes $ 70,818 $ 45,672 $ 44,630
The tax effects of significant items comprising the Company's net
deferred tax liability are as follows:
2000 1999 1998
(Thousands of Dollars)
Deferred tax assets:
Regulatory liabilities $ 40,230 $ 33,817 $ 28,075
Advances for construction 9,224 9,646 10,401
Other 22,488 18,586 20,512
Total 71,942 62,049 58,988
Deferred tax liabilities:
Utility plant 249,546 249,597 247,270
Regulatory assets 213,552 215,675 204,430
Conservation programs 13,561 17,396 16,866
PCA 47,189 (1,826) (2,543)
Other 17,230 12,568 18,126
Total 541,078 493,410 484,149
Net deferred tax
liabilities $469,136 $431,361 $425,161
3. COMMON STOCK:
Changes in shares of IDACORP common stock and treasury stock for
2000, 1999 and 1998 were as follows (in thousands of dollars):
COMMON STOCK TREASURY STOCK
Shares
Issued* Amount Shares Amount
Balance at December 31, 1997 37,612,351 $452,519 - $ -
Other - net - (955) - -
Balance at December 31, 1998 37,612,351 451,564 - -
Other - net - (221) - -
Balance at December 31, 1999 37,612,351 451,343 - -
Treasury shares:
Acquired - - 198,925 8,014
Issued - (744) (154,500) (6,518)
Other - net - 2,503 - -
Balance at December 31, 2000 37,612,351 $453,102 44,425 $ 1,496
*Total common shares outstanding were 37,567,926 at December 31, 2000 and
37,612,351 at December 31, 1999 and 1998.
As of December 31, 2000 there were 3,791,321 shares 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 and 750,000 shares
for the Long-Term Incentive and Compensation Plan (LTICP) (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.
In 2000, IDACORP's Board of Directors approved the repurchase of up
to 350,000 shares of outstanding common stock for distribution to
shareholders of an acquired entity as partial payment for the
acquisition. As of December 31, 2000, 156,300 shares had been
acquired (at a cost of $6.6 million) and 154,500 shares had been
issued under this plan. In January 2001, the Company repurchased an
additional 150,000 shares (at a cost of $6.2 million) for
distribution to shareholders of the acquired entity.
4. PREFERRED STOCK OF IDAHO POWER COMPANY:
The number of shares of IPC preferred stock outstanding at December
31, 2000, 1999 and 1998 were as follows:
Shares Outstanding at
December 31, Call Price
2000 1999 1998 Per Share
Preferred stock:
Cumulative, $100 par value:
4% preferred stock
(authorized
215,000 shares) 150,656 158,112 159,680 $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 $103.535 to
shares)(a) 250,000 250,000 250,000 $100.354
Auction rate
preferred stock,
$100,000 stated
value, (authorized
500 shares)(b) 500 500 500 $100,000.00
Total 551,156 558,612 560,180
(a) The preferred stock is not redeemable prior to July 1, 2003.
(b) Dividend rate at December 31, 2000 was 4.95% and ranged between
4.28% and 5.00% during the year.
During 2000, 1999 and 1998 IPC reacquired and retired 7,456 shares,
1,568 shares and 7,292 shares of 4% preferred stock. As of December
31, 2000, the overall effective cost of all outstanding preferred
stock was 6.02 percent.
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, 2000,
none had been issued.
On March 23, 2000, IPC filed a $200.0 million shelf registration
statement that can be used for first mortgage bonds (including
medium term notes), unsecured debt, or preferred stock. On December
1, 2000, $80.0 million principal amount of Secured Medium Term
Notes, Series C, 7.38% Series due 2007 were issued and proceeds from
this issuance were used for the early redemption in January 2001 of
the $75.0 million First Mortgage Bonds 9.50%, Series due 2021. At
December 31, 2000, $120.0 million of the total remained to be
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.
First mortgage bonds maturing during the five-year period ending
2005 are $30.0 million in 2001, $27.0 million in 2002, $80.0 million
in 2003, $50.0 million in 2004 and $60.0 million in 2005.
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 November 23, 1999, $80.0 million principal amount of Secured
Medium Term Notes, Series B, 7.20% Series due 2009 were issued by
IPC. Proceeds from this issuance were used to redeem at maturity,
the $80.0 million First Mortgage Bonds 8.65% Series due January
2000.
On April 26, 2000, at the request of IPC, the American Falls
Reservoir District issued its American Falls Refunding Replacement
Dam Bonds, Series 2000, in the aggregate principal amount of $19.9
million for the purpose of refunding on April 26, 2000 a like amount
of its bonds dated May 1, 1990. IPC has guaranteed repayment of
these bonds.
On May 17, 2000, tax exempt Pollution Control Revenue Refunding
Bonds Series 2000 in the aggregate principal amount of $4.4 million
were issued by Port of Morrow, Oregon for the purpose of refunding
on August 1, 2000, a like amount of its Pollution Control Revenue
Bonds, Series 1978.
At December 31, 2000, 1999 and 1998 the overall effective cost of
all outstanding first mortgage bonds and pollution control revenue
bonds was 7.52 percent, 7.62 percent and 7.69 percent, respectively.
At December 31, 2000, IDACORP Financial Services, Inc., a wholly
owned subsidiary of the Company, has $64.1 million of debt with
interest rates ranging from 6.03 percent to 8.59 percent. This debt
is collateralized by investments in affordable housing projects with
a book value of $101.7 million at December 31, 2000. Principal
amounts maturing during the five-year period ending 2005 are $9.7
million in 2001, $9.5 million in 2002, $9.2 million in 2003, $9.3
million in 2004 and $8.3 million in 2005.
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 $933.6 million in 2000, $898.1 million in 1999 and
$877.4 million in 1998. Included in investments and other property
were financial instruments totaling $20.6 million in 2000, $24.0
million in 1999 and $14.2 million in 1998. Estimated fair value of
these instruments was $26.0 million in 2000, $30.6 million in 1999
and $20.3 million in 1998.
7. NOTES PAYABLE:
At December 31, 2000, IDACORP had a $50 million three-year credit
facility that expires in December 2001, and a $100 million 364-day
credit facility that expired in February 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 amounts supported by the
bank credit facilities.
Balances and interest rates of short-term borrowings for IDACORP
were as follows:
Year Ended December 31,
2000 1999 1998
(Thousands of Dollars)
Balance at end of year $60,900 - -
Effective annual interest rate
at end of year 7.8 % - -
At December 31, 2000, IPC had regulatory authority to incur up to
$200 million of short-term indebtedness. IPC has a $120 million
multi-year revolving credit facility expiring in December 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 subject to the regulatory maximum,
and is 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,
2000 1999 1998
(Thousands of Dollars)
Balance at end of year $59,700 $19,757 $38,524
Effective annual interest rate
at end of year 6.8 % 6.1 % 6.0 %
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 $8.3 million at December 31, 2000. Additionally Ida-
West Energy has commitments totaling $33.1 million. The commitments
are generally revocable, 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
30 years. Under these contracts IPC is required to purchase all of
the output from these facilities. During the fiscal year ended
December 31, 2000, IPC purchased 862,313 MWh at a cost of $53.7
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 operations or cash flows.
9. STOCK-BASED COMPENSATION:
IDACORP has two stock-based compensation plans that align employee
and shareholder objectives related to the long-term growth of the
Company.
In 1995, SFAS No. 123, "Accounting for Stock-Based Compensation" was
issued. It encourages a fair-value based method of accounting for
stock-based compensation. As permitted by SFAS 123, the Company
adopted its disclosure-only requirements and continues to account
for stock-based compensation in accordance with the provisions of
Accounting Principles Board Opinion No. 25, "Accounting for Stock
Issued to Employees" (APB 25).
The Company adopted the 2000 Long-Term Incentive and Compensation
Plan (LTICP) for officers, key employees and directors. The LTICP
permits the grant of nonqualified stock options, incentive stock
options, stock appreciation rights, restricted stock, restricted
stock units, performance units, performance shares, and other
awards.
The maximum number of shares available under the LTICP is 750,000.
In 2000, IDACORP issued 220,000 stock options with an exercise
price equal to the market price of the Company's stock on the date
of grant. The maximum term of the options is ten years, and they
vest over a five-year period. In accordance with APB 25, no
compensation costs have been recognized for the option awards in
2000.
Stock option transactions in 2000 are summarized as follows. There
were no stock option transactions in 1999 and 1998:
Number Weighted
of average
shares exercise
price
Beginning of year - -
Options granted 220,000 $35.8125
Options exercised - -
Options cancelled - -
End of year 220,000 $35.8125
Exercisable - -
IDACORP has a restricted stock plan for certain key employees. Each
grant made under this plan has a three-year restricted period, and
the final award amounts depend on the attainment of cumulative
earnings per share performance goals. At December 31, 2000 there
were 265,766 remaining shares available under this plan.
Restricted stock awards are compensatory awards and the Company
accrues compensation expense (which is charged to operations) based
upon the market value of the granted shares. For the years 2000,
1999 and 1998, total compensation accrued under the plan was $1.5
million, $0.5 million and $0.6 million respectively.
The following table summarizes restricted stock activity for the
years 2000, 1999 and 1998:
2000 1999 1998
Shares outstanding - 43,615 43,063 38,365
beginning of year
Shares granted 34,649 23,497 21,361
Shares forfeited - (9,585) (4,063)
Shares issued (24,709) (13,360) (12,600)
Shares outstanding - end of
year 53,555 43,615 43,063
Weighted average fair
value of current year
stock grants on grant
date $ 34.44 $ 32.88 $ 37.00
Had compensation cost for the stock-based compensation plans been
determined on the basis of fair value pursuant to the provisions of
SFAS 123, net income and earnings per share would have been as
follows:
2000 1999 1998
Net income
As reported $139,883 $ 91,349 $ 89,176
Pro forma 140,186 91,145 89,155
Basic and diluted
earnings per share
As reported 3.72 2.43 2.37
Pro forma 3.73 2.43 2.37
For purposes of the pro forma calculations above, the estimated fair
value of the options and restricted stock are amortized to expense
over the vesting period. The fair value of the restricted stock is
the market price of the stock on the date of grant. The fair value
of each option granted in 2000 was estimated at the date of grant
using the Binomial option-pricing model with the following
assumptions:
Stock dividend yield 5.19%
Expected stock price volatility 27%
Risk-free interest rate 6.15%
Expected option lives 7 years
Fair value of options granted $8.42
10. BENEFIT PLANS:
Pension Plans
IDACORP has a noncontributory defined benefit pension plan covering
most employees. The benefits under the plan are based on years of
service and the employee's final average earnings. The Company's
policy is to fund with an independent corporate trustee at least the
minimum required under the Employee Retirement Income Security Act
of 1974 but not more than the maximum amount deductible for income
tax purposes. The Company was not required to contribute to the
plan in 2000, 1999 and 1998. The trustee invests the plan's assets
primarily in listed stocks (both U.S. and foreign), fixed income
securities and investment grade real estate.
IDACORP has a nonqualified, deferred compensation plan for certain
senior management employees and directors. The Company financed
this plan by purchasing life insurance policies and investments in
marketable securities, all of which are 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 benefit
cost for these plans (in thousands of dollars):
Pension Plan Deferred Compensation
Plan
2000 1999 1998 2000 1999 1998
Service cost $ 7,442 $ 8,389 $ 7,133 $ 574 $ 744 $ 572
Interest cost 16,718 16,402 15,458 1,965 1,797 1,747
Expected return on
assets (30,095) (25,240) (22,724) - - -
Recognized net
actuarial (gain)
loss (4,503) (344) (111) 242 279 255
Amortization of
prior service cost 708 708 424 (353) (325) (332)
Amortization of
transition asset (263) (263) (263) 613 613 613
Net periodic
pension cost $(9,993) $ (348) $ (83) $3,041 $3,108 $2,855
The following table summarizes the changes in benefit obligation and
plan assets of these plans (in thousands of dollars):
Pension Plan Deferred Compensation Plan
2000 1999 1998 2000 1999 1998
Change in projected
benefit obligation:
Benefit obligation at
January 1 $229,042 $253,729 $224,073 $ 26,925 $ 27,029 $ 25,067
Service cost 7,442 8,389 7,133 574 744 572
Interest cost 16,718 16,402 15,458 1,965 1,797 1,747
Actuarial loss (gain) 455 (33,014) 14,139 840 (489) 1,297
Benefits paid (12,376) (16,464) (11,774) (2,516) (2,201) (2,049)
Plan amendments - - 4,700 88 45 395
Benefit obligation at 241,281 229,042 253,729 27,876 26,925 27,029
December 31
Change in plan assets:
Fair value at January 1 340,521 290,080 256,893 - - -
Actual return on plan
assets 12,644 66,905 44,961 - - -
Employer contributions - - - - - -
Benefit payments (12,376) (16,464) (11,774) - - -
Fair value at December
31 340,789 340,521 290,080 - - -
Funded status 99,508 111,479 36,351 (27,876) (26,925) (27,029)
Unrecognized actuarial
loss (gain) (85,648)(108,057) (33,722) 6,442 5,844 6,612
Unrecognized prior
service cost 7,954 8,662 9,370 (355) (796) (1,166)
Unrecognized net
transition liability (1,178) (1,441) (1,704) 2,762 3,375 3,988
Net amount recognized $ 20,636 $ 10,643 $ 10,295 $(19,027)$(18,502)$(17,595)
Amounts recognized in the
statement of financial
position consist of:
Prepaid (accrued) pension
cost $ 20,636 $ 10,643 $ 10,295 $(26,365)$(25,815)$(25,631)
Intangible asset - - - 2,407 2,579 2,822
Accumulated other
comprehensive income - - - 4,931 4,734 5,214
Net amount recognized $ 20,636 $ 10,643 $ 10,295 $(19,027)$(18,502)$(17,595)
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
2000 1999 1998 2000 1999 1998
Discount rate 7.5% 7.5% 6.75% 7.5% 7.5% 6.75%
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 - - -
Savings Plan
IDACORP has an Employee Savings Plan which complies with Section
401(k) of the Internal Revenue Code and covers substantially all
employees. The Company matches specified percentages of employee
contributions to the plan. Matching contributions amounted to $3.4
million in 2000, $3.1 million in 1999 and $3.0 million in 1998.
Postretirement Benefits
The Company maintains a defined benefit postretirement plan
(consisting of health care and death benefits) that covers all
employees who were enrolled in the active group plan at the time of
retirement, their spouses and qualifying dependents.
The net periodic postretirement benefit cost was as follows (in
thousands of dollars):
2000 1999 1998
Service cost $ 851 $ 896 $ 720
Interest cost 3,374 2,867 2,913
Expected return on plan assets (2,522) (2,230) (1,761)
Amortization of unrecognized
transition obligation 2,040 2,040 2,040
Amortization of prior service
cost (691) (691) (280)
Amortization of unrecognized net - - (220)
gains
Net periodic post-retirement
benefit cost $ 3,052 $ 2,882 $ 3,412
The following table summarizes the changes in benefit obligation and
plan assets (in thousands of dollars):
2000 1999 1998
Change in accumulated benefit
obligation:
Benefit obligation at
January 1 $ 41,139 $ 38,615 $ 43,459
Service cost 851 896 720
Interest cost 3,374 2,867 2,913
Plan amendments 1,200 - (9,071)
Actuarial loss 5,635 1,859 3,483
Benefits paid (3,393) (3,098) (2,889)
Benefit obligation at
December 31 48,806 41,139 38,615
Change in plan assets:
Fair value of plan assets at
January 1 26,805 24,346 19,493
Actual (loss) return on plan
assets (760) 2,389 4,853
Employer contributions 3,108 2,845 2,789
Benefits paid (3,082) (2,775) (2,789)
Fair value of plan assets at
December 31 26,071 26,805 24,346
Funded status (22,735) (14,334) (14,269)
Unrecognized prior service cost (7,336) (9,227) (9,918)
Unrecognized actuarial loss
(gain) 3,361 (5,556) (7,256)
Unrecognized transition
obligation 24,480 26,520 28,560
Accrued benefit obligations
included with other deferred
credits $ (2,230) $ (2,597) $ (2,883)
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- 1-
Percentage- Percentage-
Point Point
increase decrease
Effect on total of service and
interest cost components $ 320 $ (263)
Effect on accumulated
postretirement benefit obligation $2,876 $(2,452)
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 benefit amounts included in the Company's
consolidated balance sheet (in thousands of dollars):
2000 1999 1998
Included with regulatory
assets - other $ 1,517 $ 1,889 $ 2,260
Included with other
deferred credits $(3,040) $(3,282) $(3,372)
11. UTILITY PLANT IN SERVICE AND JOINTLY-OWNED PROJECTS:
The following table sets out the major classifications of the IPC's
utility plant in service, accumulated provision for depreciation and
annual depreciation provisions as a percent of average depreciable
balance for the years 2000, 1999 and 1998 (in thousands of dollars):
2000 1999 1998
Balance Avg Balance Avg Balance Avg
Rate Rate Rate
Production $1,360,409 2.60% $1,348,531 2.60% $1,344,526 2.60%
Transmission 410,315 2.30 403,010 2.30 389,011 2.30
Distribution 811,604 3.34 786,488 3.37 736,527 3.15
General and Other 217,546 5.42 187,997 5.46 189,377 5.45
Total in service 2,799,874 2.94% 2,726,026 2.94% 2,659,441 2.87%
Accumulated
provision for
depreciation (1,142,572) (1,073,722) (1,009,387)
In service -
net $1,657,302 $1,652,304 $1,650,054
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, 2000 are as follows:
Company Ownership
Accumulated
Utility Provision
Plant In for
Name of Plant Location Service Depreciation % MW
(Thousands of Dollars)
Jim Bridger Rock Springs,
Units 1-4 WY $393,786 $ 209,98 33 707
Boardman Boardman, OR 62,382 36,022 10 55
Valmy Units 1
and 2 Winnemucca, NV 300,852 148,115 50 261
IPC's wholly owned subsidiary, Idaho Energy Resources Company, 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 $43.7 million in
2000, $41.9 million in 1999 and $46.2 million in 1998.
IPC has contracts to purchase the energy from four 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 $8.1 million in 2000, $8.8 million in 1999
and $8.7 million in 1998.
12. INDUSTRY SEGMENT INFORMATION:
The Company has identified two reportable operating segments,
Utility Operations and Energy Marketing.
The Utility Operations segment has two primary sources of revenue,
the regulated operations of IPC and income from Bridger Coal
Company, an unconsolidated joint venture also subject to regulation.
IPC's regulated operations include the generation, transmission,
distribution, purchase and sale of electricity.
Energy marketing consists of IPC's unregulated electricity marketing
and IDACORP Energy's natural gas marketing operations.
IDACORP's other operations include:
Ida-West Energy Company - a developer and manager of
independent power projects;
IdaTech, LLC - a developer of integrated fuel cell systems;
IDACORP Financial Services - an investor in affordable housing
and other real estate;
Rocky Mountain Communications, Inc. - provider of Internet services;
IDACOMM - provider of telecommunication services;
IDACORP Services - provider of energy-related products and services,
home security, satellite television,and other services;
Applied Power Company - manufacturer, supplier and distributor
of solar photovoltaic systems (sold January 2001).
The following table summarizes the segment information for the
Company's utility and energy marketing segments and the total of all
other segments, and reconciles this information to total enterprise
amounts.
Utility Energy Consolidated
Operations Marketing Other Eliminations Total
(Thousands of Dollars)
2000
Operating revenues $ 849,522 $ 145,400 $ 24,431 $ - $1,019,353
Operating income 182,020 94,589 (14,946) - 261,663
Other income 3,858 3,370 11,847 (3,115) 15,960
Interest expense 63,660 161 6,216 (3,115) 66,922
Income before income
taxes 122,218 97,798 (9,315) - 210,701
Income taxes 48,174 38,355 (15,711) - 70,818
Net income 74,044 59,443 6,396 - 139,883
Total assets 2,530,312 1,911,597 197,349 - 4,639,258
Expenditures for
long-lived assets 131,782 1,520 37,961 - 171,263
1999
Operating revenues $ 669,761 31,368 30,023 - 731,152
Operating income 181,248 21,684 (3,882) - 199,050
Other income 5,586 121 490 (1,071) 5,126
Interest expense 62,250 518 5,458 (1,071) 67,155
Income before income
taxes 124,584 21,287 (8,850) - 137,021
Income taxes 49,507 8,478 (12,313) - 45,672
Net income 75,077 12,809 3,463 - 91,349
Total assets 2,379,571 128,160 132,640 - 2,640,371
Expenditures for
long-lived assets 112,772 312 26,880 - 139,964
1998
Operating revenues $ 768,506 10,745 15,836 - 795,087
Operating income 186,723 7,963 (1,263) - 193,423
Other income 5,757 - 369 (308) 5,818
Interest expense 62,304 - 3,439 (308) 65,435
Income before income
taxes 130,176 7,963 (4,333) - 133,806
Income taxes 49,893 2,787 (8,050) - 44,630
Net income 80,283 5,176 3,717 - 89,176
Total assets 2,266,055 59,245 131,519 - 2,456,819
Expenditures for
long-lived assets 91,803 - 19,205 - 111,008
INDEPENDENT AUDITORS'REPORT
To The Board of Directors and Shareowners
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, 2000,1999 and 1998, and the related consolidated
statements of income, cash flows, retained earnings and comprehensive
income for the years then ended. Our audits also include 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 auditing standards generally
accepted in the United States of America. 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, 2000, 1999 and 1998,and the results of their
operations and their cash flows for the years then ended in conformity with
accounting principles generally accepted in the United States of America.
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
February 1, 2001
Idaho Power Company
Consolidated Statements of Income
Year Ended December 31,
2000 1999 1998
(Thousands of Dollars)
REVENUES:
General business $ 565,357 $ 516,148 $ 514,856
Off system sales 229,986 119,785 214,418
Other revenues 40,319 22,403 27,136
Total revenues 835,662 658,336 756,410
EXPENSES:
Operation:
Purchased power 398,649 106,344 185,271
Fuel expense 94,215 86,617 86,237
Power cost adjustment (120,688) (502) 21,866
Other 146,424 151,800 145,374
Maintenance 46,973 42,067 41,872
Depreciation 80,287 77,833 74,481
Taxes other than income taxes 20,166 21,719 20,725
Total expenses 666,026 485,878 575,826
INCOME FROM OPERATIONS 169,636 172,458 180,584
OTHER INCOME:
Allowance for equity funds used
during construction 2,565 1,667 300
Energy marketing activities -
net 92,637 23,206 7,429
Other - net 13,669 6,369 12,364
Total other income 108,871 31,242 20,093
INTEREST CHARGES:
Interest on long-term debt 53,253 54,150 52,270
Other interest 4,544 7,864 8,323
Allowance for borrowed funds
used during construction (2,346) (1,392) (900)
Total interest charges 55,451 60,622 59,693
INCOME BEFORE INCOME TAXES 223,056 143,078 140,984
INCOME TAXES 85,568 45,550 45,065
NET INCOME 137,488 97,528 95,919
Dividends on preferred stock 5,929 5,572 5,658
EARNINGS ON COMMON STOCK $ 131,559 $ 91,956 $ 90,261
The accompanying notes are an integral part of these statements.
Idaho Power Company
Consolidated Balance Sheets
Assets
December 31,
2000 1999 1998
(Thousands of Dollars)
ELECTRIC PLANT:
In service (at original cost) $2,799,874 $2,726,026 $2,659,441
Accumulated provision for
depreciation (1,142,572) (1,073,722) (1,009,387)
In service - Net 1,657,302 1,652,304 1,650,054
Construction work in progress 131,214 88,348 58,904
Held for future use 2,167 1,742 1,738
Electric plant - Net 1,790,683 1,742,394 1,710,696
INVESTMENTS AND OTHER PROPERTY 21,884 117,759 105,600
CURRENT ASSETS:
Cash and cash equivalents 83,494 95,038 20,029
Receivables:
Customer 215,358 83,412 102,653
Allowance for uncollectible
accounts (1,397) (1,397) (1,397)
Notes 2,945 345 467
Employee notes 4,742 4,105 4,510
Related parties 311 195 3,164
Other 4,943 7,095 5,338
Energy marketing assets 1,572,619 29,096 -
Accrued unbilled revenues 44,825 31,994 34,610
Materials and supplies (at
average cost) 24,685 28,960 30,143
Fuel stock (at average cost) 5,105 9,329 7,096
Prepayments 24,145 16,054 16,011
Regulatory assets associated
with income taxes 8,672 893 2,965
Total current assets 1,990,447 305,119 225,589
DEFERRED DEBITS:
American Falls and Milner water
rights 31,585 31,585 31,830
Company-owned life insurance 39,554 40,480 35,149
Regulatory assets associated
with income taxes 204,880 214,782 201,465
Regulatory assets - PCA 119,905 - -
Regulatory assets - other 45,750 56,137 67,212
Other 50,410 54,496 49,448
Total deferred debits 492,084 397,480 385,104
TOTAL $4,295,098 $2,562,752 $2,426,989
The accompanying notes are an integral part of these statements.
Idaho Power Company
Consolidated Balance Sheets
Capitalization and Liabilities
December 31,
2000 1999 1998
(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 362,430 362,203 362,156
Capital stock expense (4,024) (3,819) (3,823)
Retained earnings 313,800 274,181 252,137
Accumulated other
comprehensive income (loss) (921) 1,534 226
Total common stock equity 765,316 728,130 704,727
Preferred stock 105,066 105,811 105,968
Long-term debt 808,977 821,558 815,937
Total capitalization 1,679,359 1,655,499 1,626,632
CURRENT LIABILITIES:
Long-term debt due within one
year 30,077 89,101 6,029
Notes payable 59,700 19,757 38,508
Accounts payable 250,673 95,125 101,108
Notes and accounts payable to
related parties 4,212 10,076 28
Energy marketing liabilities 1,590,964 25,594 -
Taxes accrued 12,983 21,773 25,164
Interest accrued 15,002 19,122 18,364
Deferred income taxes 8,672 893 2,965
Other 19,066 16,069 12,117
Total current liabilities 1,991,349 297,510 204,283
DEFERRED CREDITS:
Deferred income taxes 452,404 428,923 420,268
Regulatory liabilities associated
with deferred investment
tax credits 66,050 67,433 69,396
Regulatory liabilities
associated with income taxes 40,230 33,817 28,075
Regulatory liabilities - PCA - 3,378 5,199
Regulatory liabilities - other 4,621 3,363 4,161
Other 61,085 72,829 68,975
Total deferred credits 624,390 609,743 596,074
COMMITMENTS AND CONTINGENT
LIABILITIES
TOTAL $4,295,098 $2,562,752 $2,426,989
The accompanying notes are an integral part of these statements.
Idaho Power Company
Consolidated Statements of Capitalization
December 31,
2000 % 1999 % 1998 %
(Thousands of Dollars)
COMMON STOCK EQUITY:
Common stock $ 94,031 $ 94,031 $ 94,031
Premium on capital stock 362,430 362,203 362,156
Capital stock expense (4,024) (3,819) (3,823)
Retained earnings 313,800 274,181 252,137
Accumulated other
comprehensive income (loss) (921) 1,534 226
Total common stock equity 765,316 46 728,130 44 704,727 43
PREFERRED STOCK:
4% preferred stock 15,066 15,811 15,968
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 105,066 6 105,811 6 105,968 7
LONG-TERM DEBT:
First mortgage bonds:
8.65% Series due 2000 - 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 60,000 60,000
7.38% Series due 2007 80,000 - -
7.20% Series due 2009 80,000 80,000 -
Maturing 2021 through
2031 with rates ranging
from 7.5% to 9.52% 230,000 230,000 230,000
Total first mortgage bonds 637,000 637,000 557,000
Amount due within one year (30,000) (80,000) -
Net first mortgage bonds 607,000 557,000 557,000
Pollution control revenue
bonds:
7 1/4% Series due 2008 - 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
Variable Rate Series 2000
due 2007 4,360 - -
Total pollution control
revenue bonds 170,460 170,460 170,460
REA notes 1,339 1,415 1,489
Amount due within one year (77) (76) (74)
Net REA notes 1,262 1,339 1,415
American Falls bond
guarantee 19,885 19,885 20,130
Milner Dam note guarantee 11,700 11,700 11,700
Debt related to investments
in affordable housing with
rates ranging from 6.03%
to 8.77% due 2000 to 2010 - 71,183 62,103
Amount due within one year - (9,025) (5,955)
Net affordable housing
debt - 62,158 56,148
Other subsidiary debt - 457 623
Unamortized premium/discount
- Net (1,330) (1,441) (1,539)
Total long-term debt 808,977 48 821,558 50 815,937 50
TOTAL CAPITALIZATION $1,679,359 100 $1,655,499 100 $1,626,632 100
The accompanying notes are an integral part of these statements.
Idaho Power Company
Consolidated Statements of
Cash Flows
Year Ended December 31,
2000 1999 1998
(Thousands of Dollars)
OPERATING ACTIVITIES:
Net income $137,488 $ 97,528 $ 95,919
Adjustments to reconcile net
income to net cash:
Unrealized (gains) losses
from energy marketing
activities 21,847 (3,502) -
Depreciation and amortization 92,677 95,154 87,044
Deferred taxes and investment
tax credits 44,911 (1,747) (10,127)
Accrued PCA costs (122,353) (891) 21,658
Change in:
Receivables and prepayments (144,077) (489) 1,985
Accrued unbilled revenue (12,831) 2,616 (1,298)
Materials and supplies and
fuel stock 5,544 (1,050) (911)
Accounts payable 156,932 28,397 (10,658)
Taxes accrued (8,326) (3,391) 1,312
Other current assets and
liabilities (3,572) 4,710 (857)
Other - net (6,843) (3,490) (10,340)
Net cash provided by operating
activities 161,397 213,845 173,727
INVESTING ACTIVITIES:
Additions to utility plant (131,711) (108,498) (89,644)
Investments in affordable
housing projects - (19,554) (19,139)
Investments in company - owned
life insurance - (5,862) -
Net cash of affiliates
transferred to parent (4,737) - -
Other - net 838 (3,066) 867
Net cash used in investing
activities (135,610) (136,980) (107,916)
FINANCING ACTIVITIES:
Proceeds from issuance of:
First mortgage bonds 80,000 80,000 60,000
Pollution control revenue bonds 4,360 - -
Long-term debt related to
affordable housing projects - 18,730 20,556
Retirement of:
First mortgage bonds (80,000) - (30,000)
Pollution control revenue bonds (4,360) - -
Long-term debt related to
affordable housing projects - (9,650) (4,838)
Subsidiary debt - (165) (3,316)
Dividends on common stock (69,850) (69,912) (69,889)
Dividends on preferred stock (5,929) (5,572) (5,658)
Increase (decrease) in short-
term borrowings 39,943 (14,607) (18,992)
Other - net (1,495) (680) (550)
Net cash used in financing
activities (37,331) (1,856) (52,687)
Net increase (decrease) in cash and
cash equivalents (11,544) 75,009 13,124
Cash and cash equivalents at 95,038 20,029 6,905
beginning of period
Cash and cash equivalents at end of
period $ 83,494 $ 95,038 $ 20,029
SUPPLEMENTAL DISCLOSURE OF CASH FLOW
INFORMATION:
Cash paid during the period for:
Income taxes $ 47,732 $ 50,532 $ 55,527
Interest (net of amount
capitalized) $ 58,090 $ 55,186 $ 53,806
Net non-cash assets of
affiliates transferred
to parent $ 17,353 $ - $ 27,534
The accompanying notes are an integral part of these statements.
Idaho Power Company
Consolidated Statements of Retained Earnings
Year Ended December 31,
2000 1999 1998
(Thousands of Dollars)
RETAINED EARNINGS, BEGINNING OF
YEAR $274,181 $252,137 $259,299
NET INCOME 137,488 97,528 95,919
Total 411,669 349,665 355,218
DIVIDENDS:
Common stock ($1.86 per share) (69,850) (69,912) (69,889)
Preferred stock (5,929) (5,572) (5,658)
TRANSFER TO IDACORP, INC. (22,090) - (27,534)
RETAINED EARNINGS, END OF YEAR $313,800 $274,181 $252,137
The accompanying notes are an integral part of these statements.
Consolidated Statements of Comprehensive Income
Year Ended December 31,
2000 1999 1998
(Thousands of Dollars)
NET INCOME $137,488 $ 97,528 $ 95,919
OTHER COMPREHENSIVE INCOME (LOSS):
Unrealized gains on securities
(net of tax of ($1,713), $677
and $2,185) (2,335) 1,017 3,385
Minimum pension liability
adjustment (net of tax of
($78),$189 and ( $2,054)) (119) 291 (3,159)
TOTAL COMPREHENSIVE INCOME $135,034 $ 98,836 $ 96,145
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 subsidiaries (IPC). At that time ownership interests
in two of IPC's subsidiaries were transferred to IDACORP at book value.
IPC's financial statements include $3.0 million of net income attributable
to the transferred subsidiaries for the year ended December 31, 1998.
On January 1, 2000 IPC's ownership interests in two additional subsidiaries
were transferred to IDACORP at book value. IPC's financial statements
include the following amounts attributable to these transferred
subsidiaries for the periods prior to January 1,2000:
As of/Year Ended
December 31,
1999 1998
Total assets $107,996 $ 90,029
Net assets 22,090 19,706
Net income 2,385 2,216
Except as modified below,the Notes to the Consolidated Financial
Statements of IDACORP included in this 2000 Annual Report on Form 10-K
are incorporated herein by reference insofar as they relate to Idaho Power
Company.
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 - Stock-Based Compensation
Note 10 - Benefit Plans
Note 11 - Utility Plant in Service and Jointly-Owned Projects
Note 1 - Derivative Financial Instruments The following table shows a
summary of the notional amounts of IPC's forward exposure (including both
sales and purchases) as of December 31, 2000 and 1999. The maximum term
related to any forward position is ten years.
December 31,2000 December 31,1999
Electricity MWh's
Total gross notional volume 34,453 10,818
The following table displays the fair value ofIPC's energy marketing
assets and liabilities (all electricity) at December 31, 2000 and 1999
and the average values for the twelve months ended December 31, 2000 (in
thousands of dollars):
Balance at December Twelve Months Balance at December
31, 2000 Average Balance 31, 1999
Assets Liabilities Assets Liabilities Assets Liabilities
$1,572,619 $1,590,964 $ 401,956 $ 397,914 $ 29,096 $ 25,594
The gain in fair value of energy trading contract positions (including
electricity forwards, futures, options and swaps)included in the income
before income taxes for the years ended December 31,2000 and 1999 were
$140.3 million and $29.7 million respectively.
Note 2 - Income Taxes
IPC has settled Federal and Idaho tax liabilities on all open years through
the 1996 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:
2000 1999 1998
(Thousands of Dollars)
Computed income taxes based on
statutory federal
income tax rate $78,070 $50,077 $49,344
Change in taxes resulting
from:
AFDC (1,719) (1,071) (420)
Investment tax credits (3,083) (3,032) (2,934)
Repair allowance (4,550) (2,800) (2,800)
Settlement of prior years 2 (478) (1,965)
tax returns
State income taxes (net of 10,060 6,070 7,630
Federal reduction)
Depreciation 8,243 7,292 5,237
Affordable housing tax - (8,934) (6,504)
credits
Other (1,455) (1,574) (2,523)
Total provision for federal
and state income taxes $85,568 45,550 45,065
Effective tax rate 38.4% 31.8% 32.0%
The provision for income taxes consists of the following:
2000 1999 1998
(Thousand of Dollars)
Income taxes currently payable:
Federal $35,259 $38,169 $45,909
State 5,398 9,128 9,283
Total 40,657 47,297 55,192
Income taxes deferred - Net of
amortization:
Federal 38,887 2,246 (8,006)
State 7,407 (2,030) (1,321)
Total 46,294 216 (9,327)
Investment tax credits:
Deferred 1,700 1,069 2,134
Restored (3,083) (3,032) (2,934)
Total (1,383) (1,963) (800)
Total provision for income
taxes $85,568 $45,550 $45,065
The tax effects of significant items comprising the Company's
net deferred tax liability are as follows:
2000 1999 1998
(Thousands of Dollars)
Deferred tax assets:
Regulatory liabilities $ 40,230 $ 33,817 $ 28,075
Advances for construction 9,224 9,646 10,401
Other 22,273 18,456 20,457
Total 71,727 61,919 58,933
Deferred tax liabilities:
Electric plant 249,546 249,597 247,270
Regulatory assets 213,551 215,675 204,430
Conservation programs 13,561 17,396 16,866
PCA 47,189 (1,826) (2,543)
Other 8,955 10,893 16,143
Total 532,802 491,735 482,166
Net deferred tax liabilities $461,075 $429,816 $423,233
Note 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 $866.3
million in 2000, $898.1 million in 1999, and $877.4 million in 1998.
Note 12- Industry Segment Information
The Company has identified two reportable operating segments, Utility
Operations and Energy Marketing. The Utility Operations segment has two
primary sources of income, the regulated operations of IPC and income from
Bridger Coal Company, an unconsolidated joint venture also subject to
regulation. IPC's regulated operations include the generation, transmission,
distribution purchase and sale of electricity. Energy marketing consists of
the Company's unregulated electricity marketing operations and, through
December 1998, natural gas marketing.
The Company's other operations include:
Ida-West Energy Company - a developer and manager of independent
power projects (ownership transferred to parent October 1998);
IDACORP Financial Services - an investor in affordable housing
(ownership transferred to parent January 2000);
Applied Power Company - manufacturer, supplier and distributor of solar
photovoltaic systems (ownership transferred to parent January 2000).
The following table summarizes IPC's segment information and reconciles
this information to total enterprise amounts:
Utility Energy Consolidated
Operations Marketing Other Eliminations Total
(Thousands of Dollars)
2000
Revenues $ 835,662 $ - $ - $ - $ 835,662
Income from
operations 169,636 - - - 169,636
Other income 16,242 94,917 (8) (2,280) 108,871
Interest expense 57,731 - - (2,280) 55,451
Income before
income taxes 128,147 94,917 (8) - 223,056
Income taxes 48,174 37,397 (3) - 85,568
Net income 79,973 57,520 (5) - 137,488
Total assets 2,530,312 1,761,611 3,175 - 4,295,098
Expenditures for
long-lived assets 131,782 - 299 - 132,081
1999
Revenues $ 658,336 $ - $ - $ - $ 658,336
Income from
operations 172,458 - - - 172,458
Other income 14,377 23,206 (6,341) - 31,242
Interest expense 56,679 - 3,943 - 60,622
Income before
income taxes 130,156 23,206 (10,284) - 143,078
Income taxes 49,507 9,143 (13,100) - 45,550
Net income 80,649 14,063 2,816 - 97,528
Total assets 2,379,571 72,023 111,158 - 2,562,752
Expenditures for
long-lived assets 112,772 - 22,685 - 135,457
1998
Revenues $ 756,410 $ - $ - $ - $ 756,410
Income from
operations 180,584 - - - 180,584
Other income 11,897 7,963 233 - 20,093
Interest expense 56,646 - 3,047 - 59,693
Income before
income taxes 135,835 7,963 (2,814) - 140,984
Income taxes 49,893 2,787 (7,615) - 45,065
Net income 85,942 5,176 4,801 - 95,919
Total assets 2,266,055 59,245 101,689 - 2,426,989
Expenditures for
long-lived assets 91,803 - 19,197 - 111,000
INDEPENDENT AUDITORS' REPORT
To The Board of Directors and Shareowner 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, 2000, 1999 and 1998, 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 auditing standards generally
accepted in the United States of America. 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, 2000, 1999 and 1998, and the results of their
operations and their cash flows for the years then ended in conformity with
accounting principles generally accepted in the United States of America.
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
February 1, 2001
SUPPLEMENTAL FINANCIAL INFORMATION, UNAUDITED
QUARTERLY FINANCIAL DATA:
The following unaudited information is presented for each quarter of 2000,
1999 and 1998 (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
2000
Revenues $186,273 $254,582 $301,014 $277,483
Income from operations 65,802 64,767 82,379 48,716
Income taxes 23,496 16,211 21,839 9,272
Net income 42,079 32,522 41,561 23,721
Earnings per share of
common stock 1.12 0.86 1.11 0.63
1999
Revenues $183,652 $184,427 $182,884 $180,190
Income from operations 62,007 47,474 48,971 40,598
Income taxes 16,700 10,525 10,574 7,874
Net income 29,501 21,242 22,019 18,588
Earnings per share of
common stock 0.78 0.56 0.59 0.49
1998
Revenues $177,336 $176,360 $240,329 $201,062
Income from operations 56,843 43,865 48,124 44,591
Income taxes 13,125 9,213 12,392 9,900
Net income 28,050 20,351 22,305 18,468
Earnings per share of
common stock 0.75 0.54 0.59 0.49
Idaho Power Company Quarter Ended
March 31 June 30 September 30 December 31
2000
Revenues $123,213 $213,081 $231,539 $267,829
Income from operations 55,966 36,139 39,959 37,572
Income taxes 21,024 19,341 28,429 16,774
Net income 33,725 32,154 43,095 28,514
Dividends on preferred
stock 1,428 1,484 1,511 1,506
Earnings on common stock 32,297 30,670 41,584 27,008
1999
Revenues $174,149 $165,072 $161,978 $157,136
Income from operations 59,829 39,724 39,942 32,963
Income taxes 16,582 10,479 10,419 8,071
Net income 30,784 22,796 23,371 20,576
Dividends on preferred
stock 1,368 1,352 1,401 1,451
Earnings on common stock 29,416 21,444 21,970 19,125
1998
Revenues $170,913 $167,132 $230,200 $188,164
Income from operations 55,769 39,097 44,037 41,681
Income taxes 13,125 9,213 12,392 10,335
Net income 29,455 21,768 23,715 20,979
Dividends on preferred
stock 1,405 1,417 1,410 1,426
Earnings on common stock 28,050 20,351 22,305 19,553
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 SCHEDULE AND REPORTS ON FORM
8-K
(a) Please refer to Item 8, "Financial Statements and Supplementary Data"
for a complete listing of all consolidated financial statements and
financial statement schedules.
(b) Reports on SEC Form 8-K. The following Report on Form 8-K was filed
for the three months ended December 31, 2000
Items Reported Date of Report Filed by
Item 7 - Financial Statements and November 21, 2000 IPC
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(a)(iii) 1-3198 3(a)(iii) Articles of Amendment to Restated
Form 10-Q Articles of Incorporation of IPC as
for 6/30/00 filed with the Secretary of State of
Idaho on June 15, 2000.
*3(b) 33-41166 4(b) Waiver resolution to Restated
Articles of Incorporation of IPC
adopted by Shareholders on May 1,
1991.
*3(c) 1-3198 3(c) By-laws of IPC amended on September
Form 10-Q 9, 1999, and presently in effect.
for 9/30/99
*3(d) 33-56071 3(d) Articles of Share Exchange, 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 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) 1-14465 3(c) Amended Bylaws of IDACORP, Inc. as
Form 10-Q of July 8, 1999.
for 6/30/99
*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, 1982
33-34222 4(d)(vi) Twenty-seventh May 1, 1986
33-00440 4(c)(iv) Twenty-eighth June 30, 1989
33-34222 4(d)(vii) Twenty-ninth January 1, 1990
33-65720 4(d)(iii) Thirtieth January 1, 1991
33-65720 4(d)(iv) Thirty-first August 15, 1991
33-65720 4(d)(v) Thirty-second March 15, 1992
33-65720 4(d)(vi) Thirty-third April 1, 1993
1-3198 4 Thirty-fourth December 1, 1993
Form 8-K
Dated
12/17/93
1-3198 Thirty-fifth November 1, 2000
Form 8-K
Dated
11/21/00
*4(b) 1-3198 4(b) Instruments relating to IPC American
Form 10-Q Falls bond guarantee (see Exhibit
for 6/30/00 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) 1-14465 4 Rights Agreement, dated as of
Form 8-K September 10, 1998, between IDACORP,
dated Inc. and the Bank of New York as
September Rights Agent.
15, 1998
*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) 1-3198 10(c) Guaranty Agreement, dated April 11,
Form 10-Q 2000, between IPC and Bank One Trust
for 6/30/00 Company, N.A., as Trustee, relating
to $19,885,000 American Falls
Replacement Dam Refinancing 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-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 1-14465 10(h)(iv) The Revised Security Plan for Board
1-3198 of Directors - a non-qualified,
Form 10-K deferred compensation plan effective
for 1998 August 1, 1996, revised March 2,
1999.
*10(h)(v)1 1-14465 10(e) IDACORP, Inc. Non-Employee Directors
Form 10-Q Stock Compensation Plan as of May
for 6/30/99 17, 1999.
*10(h)(vi) 1-3198 10(y) Executive Employment Agreement dated
Form 10-K November 20, 1996 between IPC and
for 1997 Richard R. Riazzi.
*10(h)(vii) 1-3198 10(g) Executive Employment Agreement dated
Form 10-Q April 12, 1999 between IPC and
for 6/30/99 Marlene Williams.
*10(h)(viii) 1-14465 10(h) Agreement between IDACORP, Inc. and
Form 10-Q Jan B. Packwood, J. LaMont Keen,
for 9/30/99 James C. Miller, Richard Riazzi,
Darrel T. Anderson, Bryan Kearney,
Cliff N. Olson, Robert W. Stahman
and Marlene K. Williams.
*10(h)(ix)1 1-14465 10(h)(ix) IDACORP, Inc. 2000 Long-Term
Form 10-K Incentive and Compensation Plan.
for 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.
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.
________________________
1 Compensatory plan
IDACORP, Inc.
SCHEDULE II - CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
Years Ended December 31, 2000, 1999 and 1998
Column A Column B Column C Column D Column E
Additions
Balance Charged
At Charged (Credited) Balance
Beginning to to Other At End
Classification Of Period Income Accounts Deduction(1) Of Period
(Thousands of Dollars)
5319:
2000:
Reserves Deducted From
Applicable Assets:
Reserve for
uncollectible
accounts and assets $1,397 $21,682 $ 1,658(2) $ 1,658 $23,079
Other Reserves:
Rate refunds $8,893 $ 3,505 $ - $12,398 $ -
Injuries and
damages reserve $1,500 $ - $ - $ - $ 1,500
Miscellaneous
operating reserves $8,473 $ 306 $ - $ 4,123 $ 4,656
5332:
1999:
Reserves Deducted From
Applicable Assets:
Reserve for
uncollectible
accounts $1,397 $ - $ 3,162(2) $ 3,162 $ 1,397
Other Reserves:
Rate refunds $5,356 $10,543 $ - $ 7,006 $ 8,893
Injuries and
damages reserve $1,500 $ - $ - $ - $ 1,500
Miscellaneous
operating reserves $6,907 $ 3,242 $ - $ 1,676 $ 8,473
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
5359:
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, 2000, 1999 and 1998
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 caused this report to be signed
on its behalf by the undersigned, thereunto duly authorized.
IDACORP, Inc.
(Registrant)
March 16, 2001 By: /s/Jan B.
Packwood Jan B. Packwood
President 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/ Jon H. Miller Chairman of the Board March 16,
2001
Jon H. Miller
By:/s/ Jan B. Packwood President and Chief "
Executive Officer
Jan B. Packwood and Director
By:/s/ J. LaMont Keen Senior Vice President - "
Administration
J. LaMont Keen and Chief Financial
Officer (Principal
Financial Officer)
By:/s/ Darrel T. Anderson Vice President - Finance "
and Treasurer
Darrel T. Anderson (Principal Accounting
Officer)
By:/s/ Rotchford L. Barker By:/s/ Jack K. Lemley "
Rotchford L. Barker Jack K. Lemley
Director Director
By:/s/ Robert D. Bolinder By:/s/ Evelyn Loveless "
Robert D. Bolinder Evelyn Loveless
Director Director
By:/s/ John B. Carley By:/s/ Peter S. O'Neill "
John B. Carley Peter S. O'Neill
Director Director
By:/s/ Peter T. Johnson By:/s/ Robert A. Tinstman "
Peter T. Johnson Robert A. Tinstman
Director Director
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has caused this report to be signed
on its behalf by the undersigned, thereunto duly authorized.
IDAHO POWER COMPANY
(Registrant)
March 16, 2001 By:/s/Jan B. Packwood
Jan B. Packwood
President 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/ Jon H. Miller Chairman of the Board March 16,
2001
Jon H. Miller
By:/s/ Jan B. Packwood President and Chief "
Executive
Jan B. Packwood Officer and Director
By:/s/ J. LaMont Keen Senior Vice President - "
Administration
J. LaMont Keen and Chief Financial
Officer
(Principal Financial
Officer)
By:/s/ Darrel T. Anderson Vice President - Finance "
and Treasurer
Darrel T. Anderson (Principal Accounting
Officer)
By:/s/ Rotchford L. Barker By:/s/ Jack K. Lemley "
Rotchford L. Barker Jack K. Lemley
Director Director
By:/s/ Robert D. Bolinder By:/s/ Evelyn Loveless "
Robert D. Bolinder Evelyn Loveless
Director Director
By:/s/ John B. Carley By:/s/ Peter S. O'Neill "
John B. Carley Peter S. O'Neill
Director Director
By:/s/ Peter T. Johnson By:/s/ Robert A. Tinstman "
Peter T. Johnson Robert A. Tinstman
Director Director
EXHIBIT INDEX
Exhibit Page
Number Number
10(h)(ix) IDACORP, Inc. 2000 Long-Term
Incentive and Compensation
Plan.
12 Statements Re: Computation of
Ratio of Earnings to Fixed
Charges. (IDACORP, Inc.)
12(a) Statements Re: Computation of
Supplemental Ratio of
Earnings to Fixed Charges.
(IDACORP, Inc.)
12(b) Statements Re: Computation of
Ratio of Earnings to Combined
Fixed Charges and Preferred
Dividend Requirements.
(IDACORP, Inc.)
12(c) Statements Re: Computation of
Supplemental Ratio of
Earnings to Combined Fixed
Charges and Preferred
Dividend Requirements.
(IDACORP, Inc.)
12(d) Statements Re: Computation of
Ratio of Earnings to Fixed
Charges. (IPC)
12(e) Statements Re: Computation of
Supplemental Ratio of
Earnings to Fixed Charges.
(IPC)
12(f) Statements Re: Computation of
Ratio of Earnings to Combined
Fixed Charges and Preferred
Dividend Requirements. (IPC)
12(g) Statements 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.