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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
X ANNUAL REPORT PURSUANT TO SECTION 13 OR 15 (D) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2001
OR
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from .......to..........
Exact name of Registrant as specified in IRS Employer
Commission its charter, address of principal executive Identification
File Number offices and telephone number Number
1-14465 IDACORP, Inc. 82-0505802
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
Common Stock, without par value New York and Pacific
Preferred Stock Purchase Rights
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT: None
Indicate by check mark whether the registrant (1) has filed all
reports required to be filed by Section 13 or 15(d) of the
Securities Exchange Act of 1934 during the preceding 12 months (or
for such shorter period that the registrant was required to file
such reports), and (2) has been subject to such filing requirements
for the past 90 days.
Yes ( X ) No ( )
Indicate by check mark if disclosure of delinquent filers pursuant
to Item 405 of Regulation S-K is not contained herein, and will not
be contained, to the best of 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 (February 28, 2002): 1,429,987,610
Number of shares of common stock outstanding at February 28, 2002:
37,590,494
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 2002 Annual Meeting of
Shareholders to be held on May 16, 2002.
GLOSSARY
AFDC - Allowance for Funds Used During Construction
APB - Accounting Principles Board
APC - Applied Power Company
BPA - Bonneville Power Administration
Cal ISO - California Independent System Operator
CalPX - California Power Exchange
CSPP - Cogeneration and Small Power Production
DIG - Derivatives Implementation Group
DSM - Demand-Side Management
EITF - Emerging Issues Task Force
EPA - Environmental Protection Agency
EPS - Earning per share
FASB - Financial Accounting Standards Board
FERC - Federal Energy Regulatory Commission
FPA - Federal Power Act
Ida-West - Ida-West Energy
IE - IDACORP Energy
IFS - IDACORP Financial Services
IPC - Idaho Power Company
IPUC - Idaho Public Utilities Commission
IRP - Integrated Resource Plan
kW - kilowatt
kWh - kilowatt-hour
LTICP - Long-Term Incentive and Compensation Plan
MD&A - Management's Discussion and Analysis
MMbtu - Million British Thermal Units
MW - Megawatt
MWh - Megawatt-hour
OPUC - Oregon Public Utility Commission
Overton - Overton Power District No. 5
PCA - Power Cost Adjustment
PG&E - Pacific Gas and Electric Company
PUCN - Public Utility Commission of Nevada
PURPA - Public Utilities Regulatory Policy Act
REA - Rural Electrification Administration
RFP - Request for proposals
RMC - Risk Management Committee
RTOs - Regional Transmission Organizations
SCE - Southern California Edison
SFAS - Statement of Financial Accounting Standards
SPPCo - Sierra Pacific Power Company
Valmy - North Valmy Steam Electric Generating Plant
WSCC - Western Systems Coordinating Council
TABLE OF CONTENTS
Page
PART I
ITEM 1. BUSINESS 1
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 17
ITEM 6. SELECTED FINANCIAL DATA 17
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS 18
ITEM 7A.QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT
MARKET RISK 39
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA 40
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE 72
PART III
ITEM 10.DIRECTORS AND EXECUTIVE OFFICERS OF THE
REGISTRANTS* 72
ITEM 11.EXECUTIVE COMPENSATION* 72
ITEM 12.SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT* 72
ITEM 13.CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS* 72
PART IV
ITEM 14.EXHIBITS, FINANCIAL STATEMENT SCHEDULE AND REPORTS
ON FORM 8-K 72
SIGNATURES 75
*INCORPORATED BY REFERENCE.
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.
PART I
ITEM 1. BUSINESS
OVERVIEW
IDACORP, Inc. (IDACORP or the Company) is a holding company
incorporated in 1998 under the laws of the state of Idaho and is the
parent of Idaho Power Company (IPC), IDACORP Energy (IE), and
several other entities. IPC is an electric utility regulated by the
Federal Energy Regulatory Commission (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. IE markets electricity and natural
gas, and offers risk management and asset optimization services, to
wholesale customers in 31 states and two Canadian provinces.
IDACORP's other subsidiaries are:
Ida-West Energy (Ida-West) - independent power projects
development and management;
IdaTech - developer of integrated fuel cell systems;
IDACORP Financial Services (IFS) - affordable housing and
other real estate investments;
Velocitus - commercial and residential Internet service
provider;
IDACOMM - provider of telecommunications services.
IPC transferred its non-utility wholesale electricity marketing
operations to IE effective June 11, 2001.
At December 31, 2001, the Company had 1,999 full-time employees.
Of these employees, 1,688 are employed by IPC.
The Company has identified two reportable business segments, the
regulated utility operations of IPC, and the energy marketing
activities of IE. IPC and IE contributed 16 percent and 84
percent to consolidated operating revenues, respectively, during
the year ended December 31, 2001. We present additional
information about our operating segments in Note 12 to the
Consolidated Financial Statements and below in "Utility
Operations" and "Energy Marketing."
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 is
involved in the generation, purchase, transmission, distribution
and sale of electric energy in a 20,000 square mile area in
southern Idaho and eastern Oregon, with an estimated population
of 873,000. 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 and three counties in Oregon. As of December
31, 2001, IPC supplied electric energy to over 401,000 general
business customers.
IPC owns and operates 17 hydroelectric power plants, one
natural gas-fired plant 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 IPC charges to its general business customers are
determined by the various regulatory authorities. Approximately
95 percent of IPC's general business revenue and sales come from
customers in Idaho. The rates charged to these customers 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, IPC compares its actual
power supply costs to the amounts it is recovering in rates.
Most, but not all, of this difference is deferred and included in
the calculation of rates for future years. The PCA is discussed
in more detail below in "Rates" and in Note 13 to the Consolidated
Financial Statements.
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.
IPC's principal commercial and industrial customers are involved
in: food processing, electronics and general manufacturing,
lumber, beet sugar refining, and the skiing industry.
Regulation
IPC is under the regulatory jurisdiction (as to rates, service,
accounting and other general matters of utility operation) of the
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 (FPA) 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 FPA, 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 FPA 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 FPA 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 in May,
are based on forecasts of net power supply expenses and the true-up
of the prior year's forecast. During the year, the difference
between the actual costs incurred and the forecasted costs is
deferred, with interest. The balance of this deferral, called a
true-up, is then included in the calculation of the next year's PCA
adjustment.
So far in the 2001-2002 rate year actual power supply costs included
in the PCA have been significantly greater than forecast due to
purchased power volumes and prices being greater than originally
forecasted and the implementation of the voluntary load reduction
payments with Astaris and the irrigation customers. To account for
these higher-than-forecasted costs, and the unamortized portion of
the 2000-2001 PCA balance, IPC has recorded regulatory assets of
$290 million as of December 31, 2001.
In the 2001 PCA filing, IPC requested recovery of $227 million of
power supply costs. In May, the IPUC authorized recovery of $168
million, but deferred recovery of $59 million pending further
review. The approved amount resulted in an average rate increase of
31.6 percent. After conducting hearings on the remaining $59
million, the IPUC authorized recovery of $48 million plus $1 million
of accrued interest, beginning in October 2001. The remaining $11
million not recovered in rates from the PCA filing was written off
in September 2001.
Other Jurisdictions: IPC filed an application with the OPUC to
begin recovering extraordinary 2001 power supply costs in its
Oregon jurisdiction. On June 18, 2001, the OPUC approved new
rates that would recover $1 million over the next year. Under the
provisions of the deferred accounting statute, annual rate
recovery amounts were limited to three percent of IPC's 2000 gross
revenues in Oregon. During the 2001 session, the Oregon
Legislature amended the statute giving the OPUC authority to
increase the maximum annual rate of recovery of deferred amounts
to six percent for electric utilities. IPC subsequently filed on
October 5, 2001 to recover an additional three percent
extraordinary deferred power supply costs. As a result of this
filing, the OPUC issued Order No. 01-994 allowing IPC to increase
its rate of recovery to six percent effective November 28, 2001.
The Oregon deferral balance is $15 million as of December 31,
2001, net of the June 18, 2001 and November 28, 2001 recovery.
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 wholesalers. IPC's generating stations and capacities
are listed in "Item 2. Properties."
IPC's system is dual peaking, with the larger peak demand
generally occurring in the summer. The system peak demand for
2001 was 2,570 MW, set on July 2, 2001. Peak demands in 2000 and
1999 were 2,919 MW and 2,839 MW, respectively. IPC expects total
system energy requirements to grow 2.2 percent annually over the
next three years.
The amounts of electricity IPC is able to generate from its hydro
plants depend on a number of factors, primarily snowpack in the
mountains above its hydro facilities, reservoir storage, and
streamflow requirements. When these factors are favorable, IPC can
generate more electricity using its hydroelectric plants. When these
factors are unfavorable, IPC must increase its reliance on more
expensive thermal plants and purchased power.
Below normal water conditions in 2001 yielded a system generation mix
of 43 percent hydro and 57 percent thermal. Historically, under
normal water conditions, IPC's system generation mix is approximately
57 percent hydro and 43 percent thermal.
The Snake River Basin snowpack numbers offer the promise of
improved streamflows for 2002. IPC's mid-February 2002
accumulations were 84 percent of normal, compared to 51 percent at
the same time a year earlier. Even though snowpack is closer to
normal, reservoir storage is not, meaning hydro conditions will
not fully return to normal in 2002.
In September 2001, IPC placed in service Danskin Power Plant, a 90-
MW natural gas-fired combustion turbine plant, located near
Mountain Home, Idaho.
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 NorthWestern
Energy under a contract that expires December 2003 and with
Seattle City Light under a contract that expires October 2002.
IPC's generating facilities are interconnected through its
integrated transmission system and are operated on a coordinated
basis to achieve maximum load-carrying capability and reliability.
IPC's transmission system is directly interconnected with the
transmission systems of the Bonneville Power Administration (BPA),
Avista Corporation, PacifiCorp, NorthWestern Energy and
Sierra Pacific Power Company (SPPCo). Such interconnections,
coupled with transmission line capacity made available under
agreements with certain of the above utilities, permit the
interchange, purchase and sale of power among all major electric
systems in the West. IPC is a member of the Western Systems
Coordinating Council (WSCC), the Western Systems Power Pool, the
Northwest Power Pool, the Western Regional Transmission
Association and the Northwest Regional Transmission Association.
These groups are being formed to more efficiently coordinate
transmission reliability and planning throughout the western grid.
See "Competition - Wholesale" discussion below.
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 plans for
meeting that demand. The 2000 IRP identified a potential
electricity shortfall within our utility service territory by mid-
2004. The plan projected a 250-MW resource need in 2004 to
satisfy energy demand during IPC's peak periods. The IRP calls
for IPC to use purchases from the Northwest energy markets to meet
short-term energy needs. The 2000 IRP anticipates that after
2004, transmission constraints will not allow IPC to cover
increasing demand using wholesale purchases from the Pacific
Northwest.
As a result of the 2000 IRP, IPC issued a request for proposals
(RFP), seeking bids for 250-MWs 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, was selected by
IPC. In December 2001 IPC signed an agreement with Garnet to
define the conditions under which the utility will purchase energy
to be produced by Garnet's proposed 273-MW natural gas-fired,
combined cycle combustion turbine facility in Canyon County, Idaho,
located in the southwest part of the state. In December 2001, IPC
filed an application with the IPUC requesting authorization to
include Garnet related expenses in the Company's PCA. On February
27, 2002, the IPUC tentatively set hearings in June 2002 to hear
Idaho Power's request.
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 $45 million in 2001. During 2001, IPC purchased
728,155 MWh 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 five entities. These contracts are for various amounts of
energy, up to 36 average megawatts, and are of various lengths
expiring between 2002 and 2009.
Transmission Services: IPC has a long history of providing wholesale
transmission service and provides various firm and non-firm wheeling
services for several surrounding utilities. IPC's system lies
between and is interconnected to the winter-peaking northern and
summer-peaking southern regions of the western interconnected power
system. This position allows IPC to provide transmission services
and reach a broad power sales market.
In December 1999, the FERC issued Order No. 2000 encouraging
companies with transmission assets to form Regional Transmission
Organizations (RTOs). See further discussion in "Competition -
Wholesale."
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.
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. Black Butte is expected to
discontinue delivery to the Valmy project as IPC has fulfilled its
purchase obligation specified in the coal supply agreement. This
agreement had provided for Black Butte to supply coal to the Valmy
project under a flexible delivery schedule that allowed for
variations in the number of tons to be delivered ranging from a
minimum of 300,000 tons per year to a maximum of one million tons
per year.
SPPCO is currently negotiating a coal sales agreement with Arch
Coal Sales Company, Inc. to supply coal to the Valmy project from
2002 through 2006. IPC would be obligated to purchase one-half of
the coal, ranging from approximately 515,000 tons to 762,500 tons
annually, under this agreement.
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 FPA. 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 proceeding
and 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 and facilities
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 2002 capital expenditures for environmental matters, excluding
allowance for funds used during construction (AFDC), will total $14
million. Studies and measures related to mitigation of environmental
concerns due to relicensing of hydro facilities account for $10
million and investments in environmental equipment and facilities at
the thermal plants account for $4 million. During the 2003-2004
period, environmental-related capital expenditures are estimated to
be $31 million. IPC anticipates $23 million in annual operating
costs for environmental facilities during the 2002-2004 period.
Clean Air: IPC has analyzed the Clean Air Act legislation and its
effects upon IPC and its customers. IPC's coal-fired plants in
Oregon and Nevada 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. IPC has sufficient
SO2 allowances to provide compliance for all three coal-fired
facilities and its Danskin natural gas-fired facility. Therefore,
IPC does not foresee any 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 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. No ruling has been made by the court as of
December 31, 2001. Impacts of the ozone and PM regulations and
regional haze regulations on IPC's thermal operations are unknown at
this time.
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.
The Danskin gas turbine plant in Mountain Home is operating in
compliance with a "permit to construct" issued by the Idaho
Department of Environmental Quality. The units are fitted with dry-
low- NO x burners and a continuous emissions monitoring system.
This should ensure that the facility will operate within the permitted
federal and state NO x and carbon monoxide limits.
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 by the Idaho Department of Fish and Game. At
December 31, 2001, the investment in these facilities was $10 million
and the annual cost of operation pursuant to FERC License 1971 is
approximately $2 million.
Endangered Species: Several species of fish and Snake River snails
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 and
Legal 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. 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 less than $1 million each year from 1999
to 2001. IPC believes that all generation facilities are presently
non-PCB.
Competition
Retail: 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.
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 changes
and conforming regulations may result in increased 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.
Wholesale: The 1992 Energy Act (Energy Act) and the FERC's
rulemaking activities have established the regulatory framework to
open the wholesale energy market to competition. The Energy Act
permits utilities to develop independent electric generating
plants for sales to wholesale customers, and authorizes the FERC
to order transmission access for third parties to transmission
facilities owned by another entity. The Energy Act does not,
however, permit the FERC to require transmission access to retail
customers. Open-access transmission for wholesale customers
provides energy suppliers with opportunities to sell and deliver
electricity at market-based prices.
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 No. 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 efficient, competitive 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 entity
that will operate the transmission grid in seven 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.
This FERC filing represents a 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. There will also need to be filings
for state approvals. IPC expects the "Stage 2" FERC filing to be
completed by March 2002. State filings may be initiated in late
2002.
Utility Operating Statistics
The following table presents IPC's revenues and volumes for the last
three years:
Years Ended December 31,
2001 2000 1999
Revenues (millions of dollars)
Residential $ 260 225 214
Commercial 164 132 123
Industrial 154 133 117
Irrigation 72 75 62
Total general business 650 565 516
Off system sales 220 230 120
Other 44 42 24
Total $ 914 837 660
Energy use (thousands of MWhs)
Residential 4,307 4,393 4,200
Commercial 3,380 3,404 3,194
Industrial 3,925 4,808 4,666
Irrigation 1,419 1,993 1,706
Total general business 13,031 14,598 13,766
Off system sales 2,387 4,529 5,924
Total 15,418 19,127 19,690
ENERGY MARKETING
In January 1997, IPC began implementing a strategy to become a
competitive energy provider throughout the western markets. In
order to compete as an energy provider of choice, IPC built a
trading operation to participate in the electricity, natural gas
and other related markets. In 1997 IPC developed natural gas
trading operations which were transferred to IE in 1999.
Effective June 11, 2001, IPC transferred its non-utility
wholesale electricity marketing operations ("Energy Marketing")
to IE.
IE has offices in Boise, Idaho and Houston, Texas and employed
approximately 120 people at December 31, 2001. IE's energy marketing
strategy has produced increasingly positive results through growing
the volume of energy delivered, expanding the geographic area in
which IE does business, and capitalizing on the recent high
volatility of energy prices. While IE continues to be active
in the natural gas markets, its business expansion has primarily
been driven from three interdependent strategies in the electricity
markets. First, IE uses its expertise in the physical power
system within the western United States to purchase the rights
to strategic transmission. While IE has no obligation to renew
these rights annually, many of them can be extended indefinitely,
barring any regulatory changes, giving it the ability to assess
the value of the rights on an annual basis before renewal.
The second piece of its strategy is to buy and sell energy
around these contractual transmission assets and take advantage
of market price movements between regions while limiting its
market risk. Third, IE uses its knowledge of the physical
system coupled with its risk management expertise to create
customized, or structured, energy solutions for end-use customers.
Additionally, IE offers asset management services to utilities and
other regulated energy providers. One such agreement is with the
Company's affiliate, IPC. Concurrent with the June 2001 transfer of
the non-utility electricity marketing business from IPC to IE, IE
and IPC entered into an Electricity Supply Management Services
Agreement (Agreement). IPC received approval of the Agreement from
the IPUC, OPUC and the FERC. Under the Agreement, IPC will continue
to own, operate and maintain its electric generating equipment and
transmission facilities (system resources) and be responsible for
system reliability. IE will manage and dispatch the system resources
to balance generation and load within the IPC operating area.
Revenues for the energy marketing segment, including intersegment
revenues, for 2001, 2000 and 1999 were $4,893 million, $2,462 million
and $872 million respectively. The growth in revenue was due to
an increase in wholesale electricity prices and growth in settled
physical electricity volume from 14.4 million MWh's in 1999 to 23.5
million MWh's in 2000 and 34.9 million MWh's in 2001.
Risk Management: 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
can withstand potentially dramatic market fluctuations. To manage
the risks inherent in the energy commodity industry while
implementing the Company's business strategy, the Risk Management
Committee (RMC), comprised of Company officers, oversees the
Company's risk management program as defined in the 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.
To manage the risks inherent in its portfolio, the Company has
established risk limits. Market and credit risk is measured and
reported daily to the members of the RMC. Other tools used to
manage credit risk are the holding of collateral in the form of cash
or letters of credit and the use of margining agreements with
counterparties when credit risk exceeds certain pre-determined
thresholds. Because of the volatile nature of energy market prices,
margining agreements can require the posting of large amounts of
cash between counterparties to hold as collateral against the value
of the energy contracts. This practice mitigates credit risk but
increases the need for cash or other liquid securities to ensure the
ability to meet all margin requirements when the markets are most
volatile.
At year-end 2001, 69 percent of the credit exposure related to IE's
unrealized positions is with investment grade counterparties. Less
than 0.5 percent is with non-investment grade counterparties. The
remaining 31 percent of year-end credit exposure is with non-rated
counterparties. The majority of the non-rated entities are
municipalities, public utility districts and electric cooperatives.
See further discussion in Part II Item 7 "Management's Discussion
and Analysis - Market Risk."
Supply: IE's supply of electricity and natural gas is purchased
directly from producers as well as other energy marketers. Sales of
energy are made to other marketers, investor owned utilities,
municipalities and cooperatives as well as large commercial and
industrial customers in regions that allow retail customer choice.
Approximately 55 percent of the marketing and trading business in
2001 was with other marketing companies.
Competition: Competition in energy marketing and trading
continues to increase. There are over 150 counterparties active
in the energy markets in the WSCC and all are increasing in their
sophistication. IE anticipates that lower prices and decreased
volatility may negatively impact its business. While IE is not
dependent on market prices for income, its profitability does
depend upon volume and spread. Both bid/ask spread and regional
pricing spreads are typically much lower during periods of lower
prices. Further, deteriorating credit conditions of our counter
parties are limiting IE's ability to transact with those counter
parties, decreasing the rate of growth of transaction volume.
While disciplined adherence to IE's policy toward credit may
limit short term profitability, IE believes it is prudent to do
so in order to manage risks properly and sustain the quality of
earnings in the long run.
Energy Marketing Operating Statistics
The following table presents IE's revenues and volumes (including
intersegment transactions) for the last three years:
Years Ended December 31,
2001 2000 1999
Revenues (Millions of dollars)
Electricity $ 4,531 $ 2,191 $ 594
Gas 362 271 278
Total $ 4,893 $ 2,462 $ 872
Operating Volumes (Settled)
Electricity (MWhs) 34,936,951 23,518,454 14,433,650
Gas (mmbtu's) 97,327,432 80,728,530 141,432,755
IDA-WEST
Ida-West develops, acquires, constructs, finances, owns and operates
electric power generation facilities. Ida-West has a 50 percent
interest in nine operating hydroelectric plants with a total
generating capacity of 45 MW.
Ida-West is developing the 273-MW Garnet Energy Facility, which will
begin operation as soon as 2004, in Canyon County, Idaho. This
facility will provide up to 250 MW for IPC's future peak energy
needs. The project is the result of a competitive bidding process
conducted by IPC, which has indicated it will face an electric
energy shortfall during certain months beginning as soon as the
summer of 2004. Garnet, a combined-cycle combustion turbine
project, is capable of expansion to 540 MW.
In 2001 the Friant Power Authority redeemed bonds that represented
Ida-West's investment in the Friant Power Project, a 27.4 MW project
located in California. The Friant bonds were originally acquired in
1996. Ida-West recorded a pre-tax gain of $5 million on this
transaction in 2001.
In 2000, Ida-West sold its interest in the Hermiston Power project,
a 536-MW gas-fired project currently under construction 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.
IPC has purchased all of the power generated by Ida-
West's four Idaho hydroelectric projects, at a cost of $6 million in
2001.
IDATECH
IdaTech was organized in 1996 as Northwest Power Systems, LLC
with the intent to bring fuel cell technology to market. In
April 1999 IDACORP purchased a majority interest in IdaTech.
IdaTech is a developer of fuel processors and proton-exchange-
membrane fuel cell systems. These fuel cell systems are designed
with various outputs for stationary and portable electric power generation.
With six patents issued and more than 50 pending, IdaTech's development
efforts are focused on the commercialization of a methanol fuel processor,
which is capable of producing a very high level of pure hydrogen.
Additionally, the company is strengthening its ability to reform other
conventional fuels including natural gas, propane, and kerosene.
In 2001 IdaTech began the design, production and delivery of the first
beta fuel cell systems for testing in 2001 and 2002, as agreed upon in
a contract with the Bonneville Power Administration. IdaTech is also
field-testing its fuel cell systems in Japan in cooperation with Tokyo
Boeki, Ltd., and in Europe in cooperation with Electricite De France (EDF).
IdaTech anticipates commercialization of its methanol fuel processor
module in 2002, and also plans to continue field-testing its portable
fuel cell system.
IDACOMM and Velocitus
In August 2000, we formed IDACOMM, Inc. and acquired Velocitus, Inc.
(formerly Rocky Mountain Communications, Inc.), a Boise, Idaho-based
Internet service provider founded in 1992. IDACOMM and Velocitus
provide a wide range of integrated communication services to
business and residential customers in several western states,
Virginia and New York.
IDACOMM, an integrated communication provider, delivers high-speed
connectivity, using fiber optic network technology. IDACOMM's
technologies enable high-speed voice, Internet and data communications,
including video conferencing, voice-over IP, off-site training and gigabit
Ethernet service. IDACOMM's customers include Fortune 500 companies as
well as government entities and school districts. IDACOMM's Metropolitan
Area Network in Idaho's Treasure Valley serves Boise, Meridian, Nampa and
Caldwell.
Velocitus operates as a Managed Service Provider by offering high-
speed Internet access, Internet system support and other related
services such as Virtual Private Networks, Firewalls and Web Hosting
to more than 25,000 customers. Velocitus Internet serves the
traditional residential and general consumer segment. Velocitus
Broadband targets small to medium size business clients with high-
speed connectivity and security solutions, including fixed wireless
technology, allowing for rapid deployment and prompt service
installation. Velocitus Broadband is currently available to
customers in parts of Idaho, Washington, Oregon, California, New
Mexico, Arizona and Utah with additional western markets opening in
2002.
IDACORP FINANCIAL SERVICES
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, Idaho.
RESEARCH AND DEVELOPMENT
In 2001, IdaTech spent approximately $7 million for research and
development of fuel cell technology. IdaTech's research and
development program is focused on the adaptation of its methanol
fuel processor to operate on all commercially important fuels.
Highest priority is given to liquid petroleum gas, natural gas, and
kerosene or diesel fuels.
IdaTech continues its policy of aggressively pursuing patent
protection of its methanol fuel processor in North America, Europe,
South America, Asia, and Australia. The patents issued to IdaTech
address the design and operation of novel fuel reformers and
hydrogen purification devices based on a two-stage hydrogen-
selective metal membrane. Cost reduction through improved designs
and reduced use of expensive materials are useful objectives of
these patents. Additionally, one patent issued to IdaTech in 2001
claims an optimized method for purging hydrogen from the anode
compartment of a PEMFC (Proton Exchange Membrane Fuel Cell) stack so
as to minimize the loss of hydrogen fuel without adversely affecting
the electrical power output from the PEMFC stack. Currently, six-
20 year US patents have been issued to IdaTech. More than 50
pending domestic and foreign patent applications addressing various
aspects of fuel processor design, operation, materials, and
integration with fuel cell stacks.
In 2001, IPC spent approximately $2 million to promote energy
efficiency, including payments of $1 million to the Northwest
Energy Efficiency Alliance and amounts totaling less than $1
million to low-income weatherization programs in Idaho and Oregon.
In addition to increasing the funding level for low-income
weatherization, IPC began a new conservation program late in the
year funded through a conservation credit from the BPA to assist
customers coping with higher winter electricity bills.
During 2001, IPC spent less than $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: risk based system planning, understanding
green power markets, wind generated electricity and renewable
energy application in distribution generation.
CAPITAL REQUIREMENTS
Capital expenditures of $660 million and debt maturities of $157
million are expected to be paid from 2002 through 2004. IPC utility
construction expenditures exclude AFDC. Over the next three years
internally generated cash and debt issuances are expected to meet
the majority of the funds needed to meet our capital requirements.
Internally generated cash is expected to provide 100 percent in
2002 and an average of 82 percent in 2003 and 2004.
2002 2003-2004
(Millions of dollars)
IPC Utility Capital Expenditures
(excluding AFDC):
Construction Expenditures:
Generating facilities
Hydro $ 15 $ 35
Thermal 13 27
Total generating facilities 28 62
Transmission lines and 18 46
substations
Distribution lines and 57 119
substations
General 21 40
124 267
Long-term debt maturities 27 130
Other 3 9
Total IPC Utility 154 406
Ida-West Capital Expenditures 4 130
IE Capital Expenditures 7 2
IFS Capital Expenditures 59 67
Other 11 15
Total Company $235 $620
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.
Ida-West's capital expenditures are primarily for development of
the 273-MW Garnet Energy Facility, which is expected to begin
operation as soon as 2004.
IFS's capital expenditures are primarily for additional
investments in affordable housing projects.
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, 2001, net earnings were 6.44 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, 2001, the actual preferred
dividend earnings coverage was 2.79 times. If the dividends on
the shares of Auction Preferred Stock were to reach the maximum
allowed, the preferred dividend earnings coverage would be 2.55
times.
CREDIT RATINGS
All of the Company's publicly traded debt as well as that of IPC
have received investment grade ratings from each of the three
major credit rating agencies. The changes in the energy industry
and the recent bankruptcy of Enron Corp. have caused the rating
agencies to refocus their attention on the credit characteristics
and credit protection measures of industry participants and in
some cases the rating agencies appear to have tightened the
standards for a given rating level. The Company and IPC will
continue to evaluate their capital structures, financing
requirements, competitive strategies and future capital
expenditures to try to maintain investment grade ratings.
However, there is no assurance that these current ratings will
continue for any given period of time or that they will not be
revised by the rating agencies, if, in their respective judgments,
circumstances so warrant. Any downgrade or revision may adversely
affect the market price of the Company or IPC's securities and
serve to increase those companies' cost of capital.
Some collateral agreements in place between IE and its
counterparties include provisions requiring additional margining
in the event of a credit rating downgrade. Credit rating changes
within the investment grade category should not materially impact
the liquidity or financial condition of IE. A credit downgrade
below an investment grade rating could result in additional margin
calls that could have a material negative impact to the liquidity
of IDACORP. The Company believes its existing credit facilities
are adequate to fund these potential liquidity requirements.
ITEM 2. PROPERTIES
IPC's system includes 17 hydroelectric generating plants located
in southern Idaho and eastern Oregon (detailed below), one natural
gas-fired plant and an interest in three coal-fired steam electric
generating plants. The system also includes approximately 4,653
miles of high voltage transmission lines; 21 step-up transmission
substations located at power plants; 18 transmission substations;
7 transmission switching stations; and 208 energized distribution
substations (excludes mobile substations and dispatch centers).
IPC holds licenses under the FPA 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 1999 (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 2040
Steam and 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
Danskin (gas-fired) 100,000 90,000
Salmon (diesel-internal
combustion) 5,500 5,000
(a) Renewed on a year-to-year basis; application for relicense is
pending.
At December 31, 2001, the composite average ages of the principal
parts of IPC's system, based on dollar investment, were:
production plant, 18 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 FPA 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.
Jim Bridger, Valmy and Boardman are jointly owned generating
facilities. IPC's ownership percentages are thirty-three, fifty
and ten, respectively.
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 nine operating hydroelectric plants
with a total generating capacity of 45 MW.
Relicensing
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 will continue
for the next ten to 15 years, depending on environmental issues
and political processes.
The most significant relicensing effort is the Hells Canyon
Complex, which provides over half of IPC's hydro generation
capacity and 40 percent of its total generating capacity.
Presently, IPC is developing its draft license application with
the assistance 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 draft license
application in September 2002, with the final application
following 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, was used by the
FERC to produce a draft EIS for these projects in January 2002. A
final EIS is expected in August 2002.
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 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 June 2002.
The Upper and Lower Malad projects are on schedule to file the new
license application in July 2002. The draft application was sent
to agencies and non-governmental organizations in October 2001.
ITEM 3. LEGAL PROCEEDINGS
IE filed a lawsuit on November 30, 2001 in Idaho State District
Court in and for the County of Ada against Overton Power District
No. 5, a Nevada electric improvement district, for failure to meet
payment obligations under a power contract. The contract provided
for Overton to purchase 40 megawatts of electrical energy per hour
from IE at $88.50 per megawatt hour, from July 1, 2001 through
June 30, 2011. In the contract, Overton agreed to raise its rates
to its customers to the extent necessary to make its payment
obligations to IE under the contract.
IE has asked the Idaho District Court for damages pursuant to the
contract, for a declaration that Overton is not entitled to
renegotiate or terminate the contract and for injunctive relief
requiring Overton to raise rates as agreed.
On December 14, 2001, IE notified Overton that the contract was
terminated due to their failure to meet payment obligations.
IE believes that Overton's breach of contract is completely
without basis and intends to vigorously prosecute this lawsuit.
While the outcome of litigation is never certain, IE believes it
should prevail on the merits. At December 31, 2001, the Company
had a $74 million long-term asset related to the Overton claim.
IE will review the recoverability of the asset on an ongoing
basis.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None
EXECUTIVE OFFICERS OF THE REGISTRANT
The names, ages and positions of all of the executive officers of
the Company are listed below along with their business experience
during the past five years. 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.
Name, Age and Position Business Experience During Past Five
(5) Years
Jan B. Packwood, 58 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, 49 Appointed March 1, 2002. Mr. Keen
Executive Vice President was Senior Vice President,
Administration and Chief Financial
Officer from May 5, 1999 to March 1,
2002, Senior Vice President-
Administration, Chief Financial
Officer and Treasurer 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, 47 Appointed March 1, 2002. Mr. Riazzi
Executive Vice President was Senior Vice President, Generation
and Marketing from March 15, 1999 to
March 1, 2002 and Vice President -
Marketing and Sales from January 14,
1999 to March 15, 1999.
Darrel T. Anderson, 43 Appointed March 1, 2002. Mr.
Vice President, Chief Anderson was Vice President, Finance
Financial Officer and and Treasurer from May 5, 1999 to
Treasurer March 1, 2002.
Bryan Kearney, 39 Appointed March 15, 2001.
Vice President and Chief
Information Officer
Gregory W. Panter, 53 Appointed April 1, 2001.
Vice President - Public
Affairs
Robert W. Stahman, 57 Appointed February 2, 1998.
Vice President, General
Counsel and Secretary
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON STOCK AND RELATED
STOCKHOLDER MATTERS
IDACORP's common stock (without par value) is traded on the New
York and Pacific Stock Exchanges. At December 31, 2001, there
were 20,910 holders of record and the year-end stock price was
$40.60 per share.
The following table shows the reported high and low sales price
and dividends paid for the years 2001 and 2000 as supported by the
New York Stock Exchange.
2001 Quarters
Common Stock, without par 1st 2nd 3rd 4th
value:
High $49.38 $41.10 $39.94 $41.14
Low 33.80 34.88 33.55 35.33
Dividends paid per
share (in cents) 46.5 46.5 46.5 46.5
______________________________
2000 Quarters
Common Stock, without par 1st 2nd 3rd 4th
value:
High $53.00 $37.00 $48.69 $51.81
Low 25.94 31.00 32.38 43.38
Dividends paid per
share (in cents) 46.5 46.5 46.5 46.5
ITEM 6. SELECTED FINANCIAL DATA
SUMMARY OF OPERATIONS (millions of dollars except for per share
amounts)
For the Years Ended
December 31, 2001 2000 1999 1998 1997
Operating revenues $5,648 $2,996 $1,433 $1,419 $ 834
Income from operations 243 248 187 181 181
Net income 125 140 91 89 87
Earnings per average
share outstanding
(basic and diluted) 3.35 3.72 2.43 2.37 2.32
Dividends declared per 1.86 1.86 1.86 1.86 1.86
share
At December 31,
Total long-term debt* 843 864 822 816 746
Total assets 3,642 4,040 2,640 2,457 2,452
*Excludes amount due within one year.
The above data should be read in conjunction with the consolidated
financial statements and notes to consolidated financial
statements included in this 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 and is the parent of Idaho Power Company
(IPC), IDACORP Energy (IE), 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 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.
IE markets electricity and natural gas, and offers risk management
and asset optimization services, to wholesale customers in 31 states
and two Canadian provinces. In June 2001, IPC transferred its non-
utility energy marketing operations to IE.
IDACORP's other operating subsidiaries include:
Ida-West Energy (Ida-West) - independent power projects
development and management;
IdaTech - developer of integrated fuel cell systems;
IDACORP Financial Services (IFS) - affordable housing and other
real estate investments;
Velocitus - commercial and residential Internet service
provider;
IDACOMM - provider of telecommunications services.
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, 2001, 2000
and 1999.
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. 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
2001 2000 1999
Utility operations $0.60 $1.97 $2.00
Energy marketing 2.87 1.58 0.34
Other operations (0.12) 0.17 0.09
Total earnings per
share $3.35 $3.72 $2.43
Return on year-end
common equity 14.4% 17.0% 12.1%
High wholesale energy prices and a severe drought had a negative
effect on utility operations from 2000 to 2001. Of the $1.37
decrease from 2000, $0.70 cents per share is attributable to
increases in power supply expenses absorbed by IPC and $0.18 per
share is due to the write-off of amounts disallowed in IPC's 2001
power cost adjustment (PCA). Additional increases in operating
expenses for maintenance, depreciation, interest and customer
expenses decreased earnings by approximately $0.34 per share.
The decrease in (earning per share) EPS from utility operations from
1999 to 2000 is predominantly the result of increased net power
supply costs of $69 million, due to declining hydroelectric
generating conditions and increased market prices for purchased
power. These costs were partially offset by a $49 million increase
in general business revenue resulting from rate increases, customer
growth, and weather conditions. In 2000 we recorded a $7 million
pension credit and in 1999 we recorded a $9 million reduction to
income for shared revenue (see "Regulatory Issues - Regulatory
Settlement").
EPS from energy marketing increased $1.29 per share in 2001 and
$1.24 per share in 2000. This strong performance was driven
primarily by increased structured origination activities, continued
price volatility and increased volumes of transactions. The annual
total volume of settled power sales increased 49 percent to 34.9
million megawatt-hours (MWh) in 2001 and increased 63 percent to
23.5 million MWh in 2000.
EPS from other operations decreased in 2001 and increased in 2000,
principally because of a gain recorded on the sale in March 2000 of
the Hermiston Power Project. This gain contributed approximately
$0.22 per share in 2000. Increased operating losses at recently
acquired subsidiaries was the primary source of the rest of the
change in EPS from other operations in both 2001 and 2000.
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 FERC. Before we discuss the
changes in income from our utility operations, we'll describe these
operations and the significant factors that influenced them in 2001
and 2000.
The main catalysts for the changes that occurred in our utility
operations were high wholesale energy prices and the drought in the
Northwest. In late 2000 and early 2001, prices for electricity in
the wholesale markets became highly volatile, reaching unprecedented
levels.
Faced with soaring demand, exorbitant prices and very little water
to produce power, we set in motion a number of measures to decrease
our reliance on the wholesale power markets, by decreasing demand
and increasing our generating capabilities. Some of these measures
were:
The IPUC approved a two-year agreement through which we
compensate our largest industrial customer, Astaris, for
reducing its load by 50 MW.
The IPUC and OPUC approved programs that compensated irrigation
customers capable of reducing usage by at least 100 MWh.
As part of the May 2001 PCA, the IPUC required IPC to implement
a tiered rate structure for Idaho residential customers. This
rate structure increases rates as a customer's usage increases.
In September 2001 we placed in service Danskin Power Plant, a
90-MW natural gas-fired combustion turbine plant, located near
Mountain Home, Idaho.
Mobile generators with total generating capacity of 40 MW were
sited at various locations in Boise during portions of the
year.
In May 2001 we made the largest filing in the nine years that our
PCA mechanism has been in effect, seeking recovery of $227 million,
96 percent of which we are now recovering.
IPC owns and operates 17 hydroelectric power plants and one natural
gas-fired plant and shares ownership in three coal-fired generating
plants. The following table presents IPC's system generation for
the last three years:
MWhs Percent of total
(in thousands) generation
2001 2000 1999 2001 2000 1999
Hydroelectric 5,638 8,500 10,652 43% 52% 59%
Thermal 7,622 7,701 7,266 57 48 41
Total system
generation 13,260 16,201 17,918 100% 100% 100%
As the table shows, we rely on low-cost hydroelectric plants for a
significant portion of our generation. Over the last ten years,
hydro generation has averaged 8.7 million MWh, 57 percent of our
total generation.
The amounts of electricity we are able to generate from these hydro
plants depend on a number of factors, primarily snowpack in the
mountains above our hydro facilities, reservoir storage, and
streamflow requirements. When these factors are favorable, we can
generate more electricity using our hydroelectric plants. When these
factors are unfavorable, we must increase our reliance on more
expensive thermal plants and purchased power.
As of this writing, Snake River Basin snowpack numbers offer the
promise of improved streamflows. Our mid-February 2002 accumulations
were 84 percent of normal, compared to 51 percent at the same time a
year earlier. Even though snowpack is closer to normal, reservoir
storage is not, meaning hydro conditions will not fully return to
normal in 2002.
Regulatory authorities determine the rates we charge to our general
business customers. Approximately 95 percent of our general
business revenue and sales come from customers in the state of
Idaho. The rates we charge these customers are adjusted annually by
a 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 volumes 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. In addition, in 2001 we put
in place several demand management programs designed to reduce
energy consumption by our customers. Finally, the significant rate
increases implemented in this year's PCA have reduced demand.
General business customer growth continued, with 2.5 percent and 2.4
percent annual increases over the last two years in our Idaho-Oregon
service territory.
The following table summarizes our utility operating results. Each
line is analyzed in more detail below.
2000-2001 1999-2000
Increase Increase
2001 2000 (Decrease) 1999 (Decrease)
(in millions of dollars)
Operating revenues:
General business $ 650 $ 565 $ 85 $ 516 $ 49
Off-system 220 230 (10) 120 110
Other 44 42 2 24 18
Total operating
revenues 914 837 77 660 177
Operating expenses:
Purchased power 584 399 185 106 293
Fuel 98 94 4 87 7
PCA (176) (121) (55) (1) (120)
Other operating
expenses 318 296 22 296 -
Total operating
expenses 824 668 156 488 180
Operating income $ 90 $ 169 $ (79) $ 172 $ (3)
General Business Revenue
The following table presents IPC's general business revenues and
volumes for the last three years:
Revenues Volumes
(in millions of (in thousands of
dollars) MWh)
2001 2000 1999 2001 2000 1999
Residential $ 260 $ 225 $ 214 4,307 4,393 4,200
Commercial 164 132 123 3,380 3,404 3,194
Industrial 154 133 117 3,925 4,808 4,666
Irrigation 72 75 62 1,419 1,993 1,706
Total $ 650 $ 565 $ 516 13,031 14,598 13,766
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.
2001 vs. 2000: In 2001, the following factors influenced the 15.0
percent increase in general business revenue:
Increased average rates, resulting from the PCA, increased
revenue $137 million. We discuss the PCA in more detail below
in "Regulatory Issues - Power Cost Adjustment";
A 2.5 percent increase in general business customers increased
revenue $16 million;
Conservation programs, including irrigation and large customer
buybacks, and other usage factors, decreased energy
consumption, reducing revenues $67 million.
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;
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 2.4 percent over
1999, increasing revenue $6 million.
Off-system sales
Off-system sales consist primarily of long-term sales contracts and
opportunity sales of surplus system energy.
$ (in millions) MWh (in thousands) Revenue per MWh
2001 2000 1999 2001 2000 1999 2001 2000 1999
$220 $230 $120 2,387 4,529 5,924 $92.14 $50.78 $20.22
2001 vs. 2000: Off-system sales decreased due principally to a 47
percent decrease in volume sold, a result of poor hydro generating
conditions. The volume decrease was partially offset by an 81
percent increase in price per MWh.
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.
Power Supply
The power supply components of operating income 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 $144 million in 2001 and $70 million
in 2000.
Purchased power
$ (in millions) MWh (in thousands) Cost per MWh
2001 2000 1999 2001 2000 1999 2001 2000 1999
$584 $399 $106 3,445 4,311 3,127 $169.52 $92.47 $34.01
2001 vs. 2000: Purchased power expenses increased $185 million in
2001. Contributing to these results are a number of factors,
including wholesale market conditions, and $132 million of
irrigation and Astaris load reduction program costs.
2000 vs. 1999: Purchased power expenses increased $293 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.
Fuel expense
$ (in millions) Thermal MWh generated
(in thousands)
2001 2000 1999 2001 2000 1999
$ 98 $ 94 $ 87 7,622 7,701 7,266
2001 vs. 2000: Expenses increased in 2001, despite decreased
generation. Average coal prices increased, and our new 90-MW gas-
fired plant went on-line in September 2001.
2000 vs. 1999: Fuel expenses increased by $7 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.
Power Cost Adjustment
The PCA component of expenses is related to IPC'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."
2001 vs. 2000: The PCA credit increased $55 million in 2001, due to
2001's power supply costs being greater than forecast, a result of
higher prices and greater volumes of purchased power and the costs
related to the load reduction programs that we introduced this year.
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.
Other Utility Operating Expenses
2001 vs. 2000: Other operations and maintenance expenses increased
$22 million in 2001. The most significant changes were:
Depreciation and amortization expenses increased $7 million,
due primarily to plant additions;
Costs at thermal plants increased a total of $7 million,
primarily due to unscheduled maintenance;
Leased diesel generators to protect against electricity supply
shortages, totaled $5 million;
Operating costs related to the implementation of our new
customer accounting system, and write-offs of uncollectible
accounts increased $4 million.
2000 vs. 1999: Other operations and maintenance expenses in 2000
were substantially unchanged from 1999. The most significant
changes were:
Pension expenses decreased $7 million due to favorable returns
on plan assets;
Distribution line maintenance expenses increased $4 million,
primarily due to increased tree clearing and pole maintenance;
Operating costs related to our customer accounting system
increased $2 million;
Depreciation expenses increased $2 million, primarily due to
plant additions.
ENERGY MARKETING
IE markets electricity and natural gas, and offers risk management
and asset optimization services, to wholesale customers in 31 states
and two Canadian provinces. IE has offices in Boise, Idaho and
Houston, Texas and employs approximately 120 people. Our energy
marketing strategy has produced increasingly positive results
through growing the volume of energy delivered, expanding the
geographic area in which we do business, and capitalizing on the
recent high volatility of energy prices. While we continue to be
active in the natural gas markets, our business expansion has
primarily been driven from three interdependent strategies in the
electricity markets. First, we use our expertise in the physical
power system within the western United States to purchase the rights
to strategic transmission. While we have no obligation to renew
these rights annually, many of them can be extended indefinitely,
barring any regulatory changes, giving us the ability to assess the
value of the rights on an annual basis before renewal. The second
piece of our strategy is to buy and sell energy around these
contractual transmission assets and take advantage of market price
movements between regions while limiting our market risk. Third, we
use our knowledge of the physical system coupled with our risk
management expertise to create customized, or structured, energy
solutions for end-use customers.
Additionally, IE offers asset management services to utilities and
other regulated energy providers. One such agreement is with our
affiliate, IPC. Concurrent with the June 2001 transfer of the non-
utility electricity marketing business from IPC to IE, IE and IPC
have entered into an Electricity Supply Management Services
Agreement (Agreement). IPC received approval of the Agreement from
the IPUC, the OPUC and the FERC. Under the Agreement, IPC will
continue to own, operate and maintain its electric generating
equipment and transmission facilities (system resources) and be
responsible for system reliability. IE will manage and dispatch the
system resources to balance generation and load within the IPC
operating area.
Operating income for IE was $177 million in 2001 compared to $95
million in 2000. Gross margin for 2001 was $243 million, $92 million
of which is unrealized gains related to the change in value of our
forward position. On a cumulative basis, we anticipate that
approximately 39 percent of these unrealized forward positions
recorded at year end 2001 will be settled by the end of 2002, 57
percent settled by the end of 2003 and 71 percent settled by the end
of 2004. All forward positions at December 31, 2001 should be
settled within 10 years. Changes in market conditions in future
periods could substantially change the amounts of gain or loss
ultimately realized upon settlement of the contracts.
Revenues
We now report on a gross revenue and gross expense basis, rather
than the netting method previously used. Settled physical sales now
are reported as revenue and settled physical purchases are reported
as operating expenses. Both revenues and expenses have been
reclassified to reflect this change.
This change has been made since the power marketing operation was
consolidated under IE. When power marketing was housed within IPC,
the gross method of reporting energy marketing revenues would have a
caused a potential distortion to the reported utility results.
Therefore, we elected to report energy marketing revenues on a net
basis. Now that power marketing is fully separated from the
utility, the gross presentation provides a more clear comparison of
our marketing and trading activities in relationship to similar
companies.
The following table presents our energy marketing revenues and
volumes (including intersegment transactions) for the last three
years:
2000-2001 1999-2000
Increase Increase
2001 2000 (Decrease) 1999 (Decrease)
(in millions of dollars)
Operating revenues:
Electricity $ 4,531 $ 2,191 $ 2,340 $ 594 $ 1,597
Gas 362 271 91 278 (7)
Total operating
revenues $ 4,893 $ 2,462 $ 2,431 $ 872 $ 1,590
Operating volumes
(settled):
Electricity
(MWh's) 34,936,951 23,518,484 11,418,467 14,433,650 9,084,834
Gas (mmbtu's) 97,327,432 80,728,530 16,598,902 141,432,755 (60,704,225)
2001 vs. 2000: The 99 percent increase in 2001 energy marketing
revenue is due primarily to increased volumes and prices. Settled
physical electricity sales increased 49 percent. Electricity prices
in 2001 were, on average, nearly 40 percent higher than in 2000.
2000 vs. 1999: The 182 percent increase in 2000 energy marketing
revenue is also due primarily to increased volumes and prices.
Settled physical electricity sales increased 63 percent.
Electricity prices in 2000 were, on average, 125 percent higher than
in 1999.
Operating Expenses
The following table presents our energy marketing operating expenses
for the last three years:
2000-2001 1999-2000
Increase Increase
2001 2000 (Decrease) 1999 (Decrease)
(in millions of dollars)
Electricity $ 4,360 $2,098 $ 2,262 $571 $ 1,527
Gas 356 269 87 279 (10)
Total operating
expenses $ 4,716 $2,367 $ 2,349 $850 $ 1,517
2001 vs. 2000: The 99 percent increase in operating expenses is
also due primarily to the increase in volumes and prices.
2000 vs. 1999: The 178 percent increase for the year is due
primarily to the increase in volumes and prices and also to an
increase in the allowance for bad debt. The expense related to bad
debt reserves in 2000 was $22 million compared to $0 in 1999. These
reserves are related to trading activities conducted with California
entities in 2000.
Contracts Accounted for at Fair Value
The commodity transactions entered into by IE are classified as
energy trading contracts, or derivatives. These contracts are
carried on the balance sheet at fair value. This accounting
treatment is also referred to as mark-to-market accounting. Mark-to-
market accounting can create a disconnect between recorded earnings
and realized cash flow. Marking a contract to market consists of
reevaluating the market value of the entire term of the contract at
each reporting period and reflecting the resulting gain or loss of
value in earnings for the period. This change in value represents
the difference between the contract price and the current market
value of the contract. The change in market value of the contract
could result in large gains or losses recorded in earnings at each
subsequent reporting period unless there are offsetting changes in
value of hedge contracts. The gain or loss in income generated from
the change in market value of the energy trading contracts is a non-
cash event. If these contracts are held to maturity, the cash flow
from the contracts, and their hedges, is realized over the life of
the contract.
When determining the fair value of our marketing and trading
contracts, we use actively quoted prices for contracts with similar
terms as the quoted price, including specific delivery points and
maturities. To determine fair value of contracts with terms that are
not consistent with actively quoted prices, we use (when available)
prices provided by other external sources. When prices from external
sources are not available, we determine prices by using internal
pricing models that incorporate available current and historical
pricing information. Finally, we adjust the fair market value of our
contracts for the impact of market depth and liquidity, potential
model error, and expected credit losses at the counterparty level.
The following table details the gross margin booked from our
marketing operations over the last three years:
2001 2000 1999
(in millions of dollars)
Gross Margin:
Realized or
otherwise settled $ 150 $ 181 $ 28
Unrealized 93 (35) 4
Total gross
margin $ 243 $ 146 $ 32
At year-end 2001, 69 percent of the credit exposure related to our
unrealized positions is with investment grade couterparties. Less
than 0.5 percent is with non-investment grade counterparties. The
remaining 31 percent of year-end credit exposure is with non-rated
counterparties. The majority of the non-rated entities are
municipalities, public utility districts and electric cooperatives.
The change in net fair value (energy marketing assets less energy
marketing liabilities) between year-end 2000 and year-end 2001 is
explained as follows (in millions of dollars):
Net fair value of contracts outstanding as of
12/31/2000 $ (3)
Contracts realized or otherwise settled during
the period (150)
Changes in net fair values attributable to
changes in valuation techniques and assumptions 7
Changes in net fair value attributable to
market prices and other market changes 284
Net fair value of contracts outstanding as of
12/31/2001 $ 138
Net fair value at year-end 2001 disaggregated by source of fair
value and maturity of contracts:
Maturity Maturity
Source of less than Maturity Maturity in excess of Grand
Fair Value 1 year 1-3 years 4-5 years 5 years Total
(in millions of dollars)
Prices actively
quoted $ 34 $ 37 $ 3 $ 0 $ 74
Prices provided
by other external
sources 16 27 (1) 6 48
Prices based on
models and other
valuation
methods 19 (5) 1 1 16
Total $ 69 $ 59 $ 3 $ 7 $ 138
Prices actively quoted are quoted daily by brokers and trading
exchanges such as NYMEX, TFS, Intercontinental, and Bloomberg. The
time horizon is January 2002 through December 2006. Products include
physical, financial, swap, interest rate, index, and basis for both
natural gas and heavy load power.
Prices provided by other external sources are quoted periodically by
brokers and trading exchanges such as TFS, APB, Prebon,
Intercontinental, and Bloomberg. The time horizon is January 2002
through December 2010. Products include physical, financial, swap,
index, and basis for both natural gas and heavy and light load
power.
Prices derived from models and other valuation methods incorporate
available current and historical pricing information. The time
horizon is January 2002 through December 2009. Products include
transmission, options, and ancillary services related to heavy and
light load power.
OTHER OPERATIONS
Other operations include the results of operations of our
diversified subsidiaries, including IDACOMM, Velocitus, Ida-West,
IdaTech, IFS, and Applied Power Company (APC) (sold in January
2001).
In August 2000, we formed IDACOMM, Inc. to provide integrated
communication services to business customers throughout the West,
using fiber optic network technology. Also, in August 2000, we
acquired a controlling interest in Velocitus (formerly Rocky
Mountain Communications, Inc.), a Boise, Idaho-based Internet
service provider. Since the acquisition, Velocitus launched a new
service-Velocitus Broadband, which emphasizes the use of fixed
wireless technology, allowing for rapid deployment of high-speed
connectivity for business customers. Velocitus currently serves
more than 25,000 subscribers of traditional and high-speed Internet
access services.
Ida-West develops, acquires, owns and manages electric power
generation projects.
In December 2001, IdaTech, a majority owned subsidiary of IDACORP,
continued to make progress by delivering nine second generation fuel
cell systems, of the first block of 50 units, to the Bonneville
Power Administration (BPA) for field testing. IdaTech continues to
develop and seek business partners in North America, Europe, and
Asia to help support the commercialization of its fuel processor and
fuel cell systems. IdaTech has delivered fuel processors and fuel
cell systems to companies in those three continents for evaluation
and testing in various field applications.
IFS, a wholly owned subsidiary of IDACORP, makes investments in
projects that provide affordable housing tax credits and historic
tax credits.
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.
Revenues
2001 vs. 2000: Other operations revenues decreased $10 million in
2001 due primarily to the sale of APC. APC generated revenues of
$16 million in 2000. This decrease was partially offset by a $5
million increase in sales at Velocitus, which was acquired in August
2000.
2000 vs. 1999: Other operations revenues decreased $4 million in
2000 due primarily to reduced sales made at APC.
Expenses
2001 vs. 2000: Other operations expenses decreased $2 million in
2001 due primarily to the sale of APC. APC incurred $17 million of
expenses in 2000. Increased expenses related to product development
activities at IdaTech ($8 million) and Velocitus ($7 million) offset
the decrease from APC.
2000 vs. 1999: Other operations expenses increased $5 million in
2000 due primarily to $5 million of increases from both Velocitus,
(acquired in August 2000), and from increased activities at IdaTech,
offset by a $5 million reduction in expenses at APC.
OTHER INCOME AND EXPENSES
Other Income
2001 vs. 2000: Other income decreased $7 million in 2001, due
primarily to the sale in 2000 of our interest in the Hermiston Power
Project, a 536-MW, gas-fired cogeneration 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. We recorded a pre-tax gain of $14 million on
this transaction in 2000. This decrease was partially offset by a
gain recognized in 2001 related to the early redemption by the
Friant Power Authority of outstanding bonds held by Ida-West.
2000 vs. 1999: Other income increased $13 million in 2000 due
primarily to the sale of our interest in the Hermiston Power
Project. We recorded a pre-tax gain of $14 million on this
transaction.
Interest Expense and Other
Interest expense and other increased $9 million in 2001 and was
unchanged in 2000. The increase in 2001 is predominantly the result
of higher short-term debt balances to finance power purchased for
IPC's system, partially offset by significant decreases in borrowing
rates. Our average short-term debt in 2001 was $232 million,
compared to $36 million in 2000.
Income taxes
Fluctuations in income tax expense result primarily from changes in
net income before taxes.
LIQUIDITY AND CAPITAL RESOURCES
Cash Flow
Operating cash flows and working capital levels declined in 2001,
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. Our net cash generated from
operations totaled $356 million for the three-year period 1999-2001.
After deducting common dividends of $210 million, net cash
generation from operations provided approximately $146 million for
our construction program and other capital requirements. Internal
cash generation after dividends provided 42 percent of our total
capital requirements in 2000 and 114 percent in 1999.
We forecast that internal cash generation after dividends will
provide approximately 100 percent of total capital requirements in
2002 and 82 percent during the two-year period 2003-2004. We expect
to continue financing our utility construction program and other
capital requirements with both internally generated funds and, as
discussed below, externally financed capital.
The following table presents IDACORP's total contractual cash
obligations:
2002 2003 2004 2005 2006 Thereafter
(in millions of dollars)
Utility long-
term debt $27 $80 $50 $60 $ - $612
Other long-
term debt 9 9 9 8 6 9
Fuel supply
contracts 38 33 30 27 19 11
At December 31, 2001, IPC had regulatory authority to incur up to
$500 million of short-term indebtedness. At December 31, 2001,
IPC's short-term borrowing totaled $282 million, consisting of $100
million of floating rate notes and $182 million of commercial paper,
compared to $60 million of commercial paper at December 31, 2000.
The increase is primarily a result of the unrecovered power supply
expenditures mentioned above.
We have bank line of credit facilities established at both IPC and
IDACORP.
IPC has a $165 million facility that expires April 26, 2002 and a
$120 million facility that expires April 18, 2002. Under these
facilities IPC pays a facility fee on the commitment, quarterly in
arrears, based on IPC's First Mortgage Bond Rating. IPC's
commercial paper may be issued up to the amount supported by the
bank credit facilities.
IDACORP has a $375 million facility that expires on April 15, 2002
and a $50 million facility that expires on April 20, 2002. Under
these facilities we pay a facility fee on the commitment, quarterly
in arrears, based on IDACORP's senior unsecured long-term debt
rating. Commercial paper may be issued up to the amounts supported
by the bank credit facilities. At December 31, 2001, IDACORP's
short-term borrowing totaled $81 million, compared to $61 million at
December 31, 2000.
IDACORP is currently in the process of renewing its credit lines at
both IDACORP (for $500 million) and IPC (for $200 million) with
closing anticipated in March 2002.
Credit Ratings
All of the Company's publicly traded debt as well as that of IPC
have received investment grade ratings from each of the three
major credit rating agencies. The changes in the energy industry
and the recent bankruptcy of Enron Corp. have caused the rating
agencies to refocus their attention on the credit characteristics
and credit protection measures of industry participants and in
some cases the rating agencies appear to have tightened the
standards for a given rating level. The Company and IPC will
continue to evaluate their capital structures, financing
requirements, competitive strategies and future capital
expenditures to try to maintain investment grade ratings.
However, there is no assurance that these current ratings will
continue for any given period of time or that they will not be
revised by the rating agencies, if, in their respective judgments,
circumstances so warrant. Any downgrade or revision may adversely
affect the market price of the Company or IPC's securities and
serve to increase those companies' cost of capital.
Some collateral agreements in place between IE and its
counterparties include provisions requiring additional margining
in the event of a credit rating downgrade. Credit rating changes
within the investment grade category should not materially impact
the liquidity or financial condition of IE. A credit downgrade
below an investment grade rating could result in additional margin
calls that could have a material negative impact to the liquidity
of IDACORP. The Company believes its existing credit facilities
are adequate to fund these potential liquidity requirements.
Working Capital
Net working capital (current assets less current liabilities)
decreased approximately $213 million from December 31, 2000 to
December 31, 2001. The most significant changes were in notes
payable and energy marketing assets and liabilities.
The primary cause of the increase in notes payable is power supply
expenditures. We discuss recovery of these costs in "Regulatory
Issues" later in the MD&A.
Energy marketing assets and liabilities reflect the fair value of
energy marketing contracts as of the reporting date. The fair value
of these contracts is unrealized and therefore does not necessarily
indicate a current source or use of funds. The decreases in energy
marketing assets and liabilities from 2000 to 2001 is primarily a
reflection of significantly lower market prices at December 31,
2001, than in the prior year. Additional netting agreements between
IE and its counterparties also contributed to a reduction in the
energy assets and liabilities. Finally, an increase in posted
collateral supporting our energy trading contracts further reduced
the energy trading liability.
Construction Program
Our consolidated cash construction expenditures totaled $180 million
in 2001, $140 million in 2000, and $111 million in 1999.
Approximately 25 percent of these expenditures were for generation
facilities, 19 percent for transmission facilities, 30 percent for
distribution facilities, and 26 percent for general plant and
equipment.
We estimate that our cash construction and acquisition programs will
require the following amounts over the next three years. These
estimates are subject to revision in light of changing economic,
regulatory, environmental, and conservation factors.
2002 2003-2004
(in millions of dollars)
Utility $124 $267
Energy marketing 7 2
Other 63 197
Total $194 $466
Financing Program
Our consolidated capital structure fluctuated slightly during the
three-year period, with common equity ending at 48 percent,
preferred stock of IPC 6 percent, and long-term debt 46 percent at
December 31, 2001.
At December 31, 2001, IPC also had $100 million of floating rate
notes outstanding, payable on September 1, 2002 included in notes
payable.
We are proceeding with our plans to issue equity and debt securities
this year. The equity issuance could take the form of common
equity, mandatorily redeemable equity securities, or both. We are
also planning to raise additional debt to provide balance in the
capital that we raise. The Company is still reviewing its options
with regard to type of securities, size and timing, but we expect
that the capital will be raised in the first half of 2002.
In February 2002, IPC notified holders of its $50 million 8 3/4%
Series First Mortgage Bonds due 2027 of its intent to redeem
these bonds on March 15, 2002.
IDACORP currently has a $300 million shelf registration statement
that can be used for the issuance of unsecured debt (including
medium-term notes) and preferred or common stock. At December 31,
2001, none had been issued.
In March 2000 IPC filed a $200 million shelf registration statement
that could be used for first mortgage bonds (including medium-term
notes), unsecured debt, or preferred stock. 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. In March 2001, IPC issued $120 million of Secured Medium-Term
Notes, with the proceeds used to reduce short-term borrowing
incurred in support of ongoing long-term construction requirements.
In August 2001, IPC filed a $200 million shelf registration that can
be used for first mortgage bonds (including medium-term notes),
unsecured debt, or preferred stock. At December 31, 2001, no
amounts have been issued.
In August 2001, $25 million of First Mortgage Bonds due in 2031 were
redeemed early.
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 $20 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 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.
CURRENT ISSUES
In this section we address a number of other issues that affect or
could affect our operations.
California Energy Situation
As a component of IPC's 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, at that time,
operated a wholesale electricity market in California by acting as a
clearinghouse through which electricity was bought and sold.
Pursuant to the participation agreement, IPC could sell power to the
CalPX under the terms and conditions of the CalPX Tariff. Under the
participation agreement, if a participant in the CalPX exchange
defaults on a payment to the exchange, the other participants are
required to pay their allocated share of the default amount to the
exchange. The allocated shares are based upon the level of trading
activity, which includes both power sales and purchases, of each
participant during the preceding three-month period.
On January 18, 2001, the CalPX sent IPC 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. IPC made this payment. On January 24, 2001, IPC
terminated the participation agreement. On February 8, 2001, the
CalPX sent a further invoice for $5.2 million, due February 20,
2001, as a result of alleged payment defaults by SCE, Pacific Gas
and Electric Company (PG&E), and others. However, because the CalPX
owed IPC $11.3 million for power sold to the CalPX in November and
December 2000, IPC did not pay the February 8th invoice. IPC
essentially discontinued energy trading with California entities in
December 2000. IPC believes that the default invoices were not
proper and that IPC owes no further amounts to the CalPX. IPC has
pursued all available remedies in its efforts to collect amounts
owed to it by the CalPX.
On February 20, 2001, IPC filed a petition with FERC to intervene in
a proceeding which requested the FERC to suspend the use of the
CalPX charge back methodology and provides for further oversight in
the CalPX's implementation of its default mitigation procedures.
A preliminary injunction was 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.
In April 2001, PG&E filed for bankruptcy. The CalPX and the
California Independent System Operator (Cal ISO) were among the
creditors of PG&E. To the extent that PG&E's bankruptcy filing
affects the collectibility of our receivables from the CalPX and Cal
ISO our receivables from these entities are at greater risk.
Also in April 2001, the FERC issued an order stating that it was
establishing price mitigation for sales in the California wholesale
electricity market. Subsequently, in its June 19, 2001 Order, the
FERC expanded that price mitigation plan to the entire western
United States electrically interconnected system. That plan
included the potential for orders directing electricity sellers into
California since October 2, 2000 to refund portions of their sales
prices if the FERC determined that those prices were not just and
reasonable, and therefore not in compliance with the Federal Power
Act. The June 19 Order also required all buyers and sellers in the
Cal ISO market during the subject time-frame to participate in
settlement discussions to explore the potential for resolution of
these issues without further FERC action. The settlement
discussions failed to bring resolution of the refund issue and as a
result, the FERC Chief Judge submitted a Report and Recommendation
to the FERC recommending that the FERC adopt his methodology set
forth in his report and set for evidentiary hearing an analysis of
the Cal ISO's and the CalPX's spot markets to determine what refunds
may be due upon application of that methodology. The Judge
recommended that his methodology should be applied to all sellers
except those who at the evidentiary hearing are able to demonstrate
that their costs exceed the results of the recommended methodology.
On July 25, 2001, the FERC issued an order establishing evidentiary
hearing procedures related to the scope and methodology for
calculating refunds related to transactions in the spot markets
operated by the Cal ISO and the CalPX during the period October 2,
2000 through June 20, 2001. As to potential refunds, if any, the
Company believes that its exposure will be more than offset by
amounts due it from California entities.
In addition, the July 25, 2001 FERC order established another
proceeding to explore whether there may have been unjust and
unreasonable charges for spot market sales in the Pacific Northwest
during the period December 25, 2000 through June 20, 2001. The FERC
Administrative Law Judge (ALJ) submitted her recommendations and
findings to the FERC on September 24, 2001. The ALJ found that the
prices were just and reasonable and therefore no refunds should be
allowed. Procedurally, the ALJ's decision is a recommendation to
the commissioners of the FERC. Multiple parties have filed requests
for rehearing and petitions for review. The ALJ has re-established
a procedural schedule which would result in finding of fact and
recommended conclusions during August 2002; such schedule is subject
to Commission review. Actions of the FERC are appealable to the
United States Court of Appeals. The Company will continue to
monitor all proceedings to determine the impact on the Company.
Counsel has been retained in connection with the CalPX and PG&E
bankruptcies and FERC proceedings.
Effective June 11, 2001, IPC transferred its non-utility wholesale
electricity marketing operations to IE. Effective with the June 11
transfer, the outstanding receivables and payables with the CalPX
and Cal ISO were assigned from IPC to IE. At December 31, 2001, the
CalPX and Cal ISO owed $13 million and $31 million, respectively,
for energy sales made to them by IPC in November and December 2000.
IE has accrued a reserve of $41 million against these receivables.
These reserves were calculated taking into account the uncertainty
of collection, given the current California energy situation. Based
on the reserves recorded as of December 31, 2001, the Company
believes that the future collectibility of these receivables or any
potential refunds ordered by the FERC would not have a significant
impact on the Company's financial position, results of operations or
cash flows.
Regulatory Issues
Idaho Jurisdiction
Power Cost Adjustment (PCA): IPC has a PCA mechanism that provides
for annual adjustments to the rates charged to its Idaho retail
electric customers. Approved in 1992, the PCA was designed to pass
through approximately 90 percent of the variance from forecasted net
power supply costs. These adjustments, which take effect annually
in May, are based on forecasts of net power supply expenses and the
true-up of the prior year's forecast. During the year, the
difference between the actual and forecasted costs is deferred with
interest. The balance of this deferral, called a true-up, is then
included in the calculation of the next year's PCA adjustment.
In the 2001 PCA filing, IPC requested recovery of $227 million of
power supply costs. In May, the IPUC authorized recovery of $168
million, but deferred recovery of $59 million pending further
review. The approved amount resulted in an average rate increase of
31.6 percent. After conducting hearings on the remaining $59
million the IPUC authorized recovery of $48 million plus $1 million
of accrued interest, beginning in October 2001. The remaining $11
million not recovered in rates from the PCA filing was written off
in September 2001.
Of the $227 million requested by IPC, $185 million related to the
true-up of power supply costs incurred in the 2000-2001 PCA year and
$42 million was for recovery of excess power supply costs forecasted
in the 2001-2002 PCA year. The forecast amount, however,
underestimated expected power supply costs due to reservoir water
levels coming in below forecast, necessitating the use of higher
cost alternatives to hydro generation. Also market prices for
purchased power were higher than forecast earlier in the PCA year.
As part of the May 2001 PCA, the IPUC required us to implement a
three-tiered rate structure for Idaho residential customers. The
IPUC determined that the approved rates for residential customers
should increase as customer's electricity consumption increases.
The residential rate increases are 14.4 percent for the first 800
kWh of usage, 28.8 percent for the next 1,200 kWh, and 62 percent
for the usage over 2,000 kWh.
On October 18, 2001 IPC filed an application with the IPUC for an
order approving the costs to be included in the 2002-2003 PCA for
the Irrigation Load Reduction Program and the Astaris Load Reduction
Agreement. These two programs were implemented in 2001 to reduce
demand and were approved by the IPUC and the OPUC. The costs
incurred in 2001 for these two programs were $70 million for the
Irrigation Load Reduction Program and $62 million for the Astaris
Load Reduction Agreement.
On August 31, 2001 IPC filed a request with the IPUC to implement a
rate credit to qualifying residential and small farm customers. The
credit is the result of a settlement agreement between IPC and the
Bonneville Power Administration (BPA), which will pass on the
benefits of the Federal Columbia River Power System. IPC estimates
the credit could be as much as $3.60 per month for residential
customers who use 1,200 kWh per month and $300 per month for farm
customers that use 100,000 kWh. The IPUC, by Order No. 28868,
approved the credit to be passed to the qualified customers
effective October 1, 2001.
In its May 2001 rate authorization the IPUC also directed IPC to
reinstate a comprehensive conservation program given the current
volatility of market prices and the opportunity to incorporate long-
term conservation. In response to that directive, IPC filed a
report of present energy efficiency activities, a list of
conservation measures, an examination of funding options and a
detailed program structure that could
be implemented should the Commission determine that additional
conservation programs, including the funding of these programs, is
in the public interest. The Commission has delayed further
deliberations until the spring of 2002.
So far in the 2001-2002 rate year actual power supply costs included
in the PCA have been significantly greater than forecast due to
purchased power volumes and prices being greater than originally
forecasted and the implementation of the voluntary load reduction
programs with Astaris and the irrigation customers. To account for
these higher-than-forecasted costs and the unamortized portion of
the 2000-2001 PCA balance, IPC has recorded a regulatory asset of
$290 million as of December 31, 2001.
The May 2000 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 increased general business revenue by approximately $38
million during the 2000-2001 rate period, partially offsetting the
forecasted increase in power supply costs.
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 1999-2000 rate period
and a true-up from the 1998-1999 rate period. Overall, the May 1999
rate adjustment decreased annual general business revenue by
approximately $40 million during the 1999-2000 rate period.
Regulatory Settlement: IPC had a settlement agreement with 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 the year-end common equity, IPC set aside 50 percent of
the excess for the benefit of the 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 $10 million in 1999 earnings and $3 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 $7
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 for the years 2000-2004, ordering IPC to set aside
the remaining $6 million of revenue sharing dollars to fund that
participation.
Demand-Side Management (Conservation) Expenses (DSM): 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.
Oregon Jurisdiction
IPC filed an application with the OPUC to begin recovering
extraordinary 2001 power supply costs in its Oregon jurisdiction.
On June 18, 2001, the OPUC approved new rates that would recover $1
million over the next year. Under the provisions of the deferred
accounting statute, annual rate recovery amounts were limited to
three percent of IPC's 2000 gross revenues in Oregon. During the
2001 session, the Oregon Legislature amended the statute giving the
OPUC authority to increase the maximum annual rate of recovery of
deferred amounts to six percent for electric utilities. IPC
subsequently filed on October 5, 2001 to recover an additional three
percent extraordinary deferred power supply costs. As a result of
this filing, the OPUC issued Order No. 01-994 allowing IPC to
increase its rate of recovery to six percent effective November 28,
2001. The Oregon deferral balance is $15 million as of December 31,
2001, net of the June 18, 2001 and November 28, 2001 recovery.
IPC filed with the OPUC a request to implement the same BPA program
as in Idaho. The OPUC held a public meeting on October 22, 2001 and
subsequently approved the Company's request to implement the BPA
Residential and Small Farm Energy Credit for the benefits derived
during the period October 1, 2001 through September 30, 2006.
In 1998, IPC received authority from the OPUC to reduce the
amortization period for the regulatory assets associated with DSM
programs from 24 years to 5 years. The OPUC also approved
additional Oregon allocated DSM expenditures for recovery through
rates. The Oregon costs will be recovered by extending an existing
surcharge until the amounts are collected.
Nevada Jurisdiction
The IPUC and PUCN approved IPC's sale of its Nevada service
territory to Raft River Electric Co-Op (Raft River). This sale
transferred the distribution facilities and rights-of-way that serve
about 1,250 customers in northern Nevada and about 90 customers in
southern Idaho. The FERC approved a power supply agreement between
IPC and Raft River. This sale will allow IDACORP to participate in
a deregulated electric utility market in Nevada should that state
resume deregulation activities.
New Idaho Legislation
Idaho Senate Bill No. 1255, chapter 15, title 61, Idaho Code (the
Act), was signed into law on April 10, 2001. It authorizes the IPUC
to allow public utilities or their assignees to issue energy cost
recovery bonds to finance, among other things, significant increases
in the cost of electricity resulting from shortfalls in available
hydroelectric power for which higher-cost replacement power must be
substituted. The legislative intent of the Act is to provide
utilities with a mechanism for recovery of these increased costs
while leveling the rate impact of such increases on the utilities'
customers. Energy cost recovery bonds must have an expected
maturity date no later than five years after issuance and a legal
maturity date no later than seven years after issuance.
Under the Act, the IPUC may issue an energy cost financing order in
favor of the utility, pursuant to which a charge, known as an energy
cost bond charge, would be included on the bills of the utility's
Idaho customers.
The Act requires the energy cost bond charge to remain in effect
until the energy cost recovery bonds are paid in full. In addition,
the charge is subject to periodic adjustment to ensure the timely
payment of principal and interest on the energy cost recovery bonds
and the recovery of certain related expenses.
An energy cost financing order creates energy cost property, which
includes the right to receive revenues arising from the energy cost
bond charge. Energy cost property may be sold or otherwise
transferred to, among others, the assignee of the public utility
that issues energy cost recovery bonds, and it may be pledged as
security for such bonds.
The Act requires that, before it issues an energy cost financing
order, the IPUC must find that the public interest would be better
served if increased costs reflected in a fuel or power cost
adjustment and related expenses were recovered through the issuance
of energy cost recovery bonds than if these amounts were recovered
over a one-year period assuming a conventional financing.
Before seeking to recover costs through the issuance of energy
bonds, IPC must file with the IPUC a proposal to establish a
threshold energy cost amount, or trigger. In June 2001, the IPUC
approved IPC's application, establishing a one cent per kWh trigger
amount.
Electric Industry Restructuring
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
identified a potential electricity shortfall within our utility
service territory by mid-2004. The plan projected a 250-MW resource
need in 2004 to satisfy energy demand during IPC's peak periods.
The IRP calls for IPC to use purchases from the Northwest energy
markets to meet short-term energy needs. The 2000 IRP anticipates
that after 2004, transmission constraints will not allow IPC to
continue to cover increasing demand using wholesale purchases from
the Pacific Northwest.
As a result of the 2000 IRP, 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, was selected by IPC.
In December 2001 IPC signed an agreement with Garnet to define the
conditions under which the utility will purchase energy to be
produced by Garnet's proposed 273-MW natural gas-fired combined
cycle combustion turbine facility in Canyon County, Idaho, located
in the southwest part of the state. In December 2001, IPC filed an
application with the IPUC requesting authorization to include Garnet
related expenses in the Company's PCA.
Regional Transmission Organizations
IPC has a long history of providing wholesale transmission services.
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 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 efficient, competitive 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 entity that
will operate the transmission grid in seven 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 previous FERC filing represents a 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. There will also need to be filings
for state approvals. We expect the "Stage 2" FERC filings to be
completed by March 2002. State filings may be initiated in 2002.
Relicensing of Hydroelectric Projects
IPC, like other utilities that operate nonfederal hydroelectric
projects, has obtained licenses for its hydroelectric projects from
the FERC. These licenses generally last for 30 to 50 years depending
on the size of the project. By 2010, the licenses for eight of our
hydro projects will have expired. We are actively pursuing the
relicensing of these 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 licenses for our Bliss, Upper Salmon Falls, Lower
Salmon Falls, CJ Strike, and Shoshone Falls Hydroelectric Projects.
The licenses for the Upper and Lower Malad Project expires in 2004,
the Hells Canyon Complex (Brownlee, Oxbow and Hells Canyon dams) in
2005, and the Swan Falls Project in 2010. We are currently engaged
in procedures necessary to file timely license applications for each
of these projects. Although various federal and state requirements
and issues must be resolved through the license renewal process, we
anticipate that we will relicense each of the 10 facilities. At this
point, however, we cannot predict what type of environmental or
operational requirements we may face, nor can we estimate the cost
of license renewal. At December 31, 2001, $39 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, 2001. IE buys and sells financial and physical
natural gas and electricity commodity contracts as part of our
ongoing business. These contracts are subject to electricity and
natural gas commodity price risk as well as interest rate risk. We
have a 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, 2001 is immaterial. We also
transact in interest rate futures and swaps to manage the interest
rate risk embedded in our commodity portfolio.
Interest Rate Risk Sensitivity
This table presents descriptions of our financial instruments at
December 31, 2001, that are sensitive to changes in interest rates.
The majority of our debt is held in fixed rate securities with
embedded call options. We owe $72 million in variable-rate tax-
exempt debt, and 29 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, 2001, based
on market rates for similar instruments as of that date.
Expected Amount Average
Maturity Date due interest rate
(in millions)
2002 $ 36 6.8%
2003 89 6.5%
2004 59 7.9%
2005 68 6.0%
2006 6 7.2%
Thereafter 550 7.4%
Total $ 808 7.2%
Fair Value $ 847
Commodity Price Risk Sensitivity
This analysis presents the December 2001 value-at-risk of 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. We also use interest rate futures and
swaps to manage the interest rate risk embedded in the energy
commodity portfolio. 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
can withstand potentially dramatic market fluctuations. To manage
the risks inherent in the energy commodity industry while
implementing our business strategy, our Risk Management Committee
(RMC), comprised of Company officers, oversees the risk management
program as defined in our risk management policy. 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. The value-at-
risk measure is a tool used by our RMC to understand on a daily
basis the potential impact to earnings arising from market price
risks as the markets change.
The value at risk at year-end 2001 of our energy marketing activity
is $1.3 million at a 95 percent confidence level and for a holding
period of one business day and $1.8 million at a 99 percent
confidence level and a one-day holding period. The average value-at-
risk for 2001 at a 95 percent confidence level and one-day holding
period was $3.9 million. The value-at-risk was calculated using an
analytic value-at-risk methodology. This methodology computes value-
at-risk based upon forward market prices and historical volatilities
as of December 31, 2001. The value-at-risk is understood to be a
forecast and is not guaranteed to occur. The 95 percent confidence
level and one-day holding period imply that there is a five percent
chance that the daily loss will exceed $1.3 million. The 99 percent
confidence level implies a one percent chance that daily loss will
exceed $1.8 million. The value-at-risk calculation is principally
affected by market prices and volatility of prices. The RMC
actively manages the risk to keep our trading activities within
trading limits.
Environmental and Legal Issues
Overton Power District No. 5
IE filed a lawsuit on November 30, 2001 in Idaho State District
Court in and for the County of Ada against Overton Power District
No. 5 (Overton), a Nevada electric improvement district, for failure
to meet payment obligations under a power contract. The contract
provided for Overton to purchase 40 megawatts of electrical energy
per hour from IE at $88.50 per megawatt hour, from July 1, 2001
through June 30, 2011. In the contract, Overton agreed to raise its
rates to its customers to the extent necessary to make its payment
obligations to IE under the contract. IE has asked the Idaho
District Court for damages pursuant to the contract, for a
declaration that Overton is not entitled to renegotiate or terminate
the contract and for injunctive relief requiring Overton to raise
rates as agreed.
On December 14, 2001, we notified Overton that we terminated the
contract due to their failure to meet payment obligations.
We believe that Overton's breach of contract is completely without
basis and intend to vigorously prosecute this lawsuit. While the
outcome of litigation is never certain, IE believes it should
prevail on the merits. At December 31, 2001, we had a $74 million
long-term asset related to the Overton claim. We will review the
recoverability of the asset on an ongoing basis.
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 November of 1991, the National Marine Fisheries Service (NMFS)
listed the Snake River Sockeye Salmon as endangered under the
Endangered Species Act (ESA). Subsequently, in April 1992, NMFS
listed the Snake River Fall Chinook and the Snake River
Spring/Summer Chinook as threatened under the ESA. Only the Snake
River Fall Chinook inhabit the Snake River in the vicinity of our
three-dam Hells Canyon Complex (HCC). These listings have not had
any major effects on our operations. In 1991, IPC voluntarily
initiated a Fall Chinook Interim Recovery Plan and Study intended to
address concerns relative to Fall Chinook spawning immediately below
Hells Canyon Dam. Since the inception of that plan, IPC has been
managing releases from the HCC during the Fall Chinook spawning
season to provide stable conditions for spawning Fall Chinook below
Hells Canyon Dam. These conditions are maintained through fry
emergence in the spring. In connection with the relicensing of the
HCC, IPC is engaged in ongoing discussions with the FERC and NMFS
relative to ESA issues associated with the HCC.
In December 2000, NMFS issued a final Biological Opinion (BiOp) on
the operation of the Federal Columbia River Power System (FCRPS).
This BiOp resulted from ESA Section 7 consultation on the operations
of the federal projects operated by the U.S. Army Corps of Engineers
and U.S. Bureau of Reclamation on the lower Snake and Columbia
Rivers. It did not relate to the operations of our HCC and did not
call for any changes in the operations of the HCC.
In May of 2001, NMFS issued a final BiOp on the operations of the
U.S. Bureau of Reclamation (BOR) projects in the Snake River basin
above the HCC. This BiOp was interim in nature, expiring in March
2002. NMFS and the BOR are currently negotiating an extension of
this BiOp for subsequent years operations.
Portions of the 2000 FCRPS BiOp and the 2001 BOR BiOp provide for
the acquisition of water from Idaho by the BOR in order to provide
augmentation flows to assist with the downstream migration of ESA
listed anadromous fish through the lower Snake River FCRPS projects.
For the past several years, the BOR has been leasing water from
willing lessors in Idaho in an effort to provide the augmentation
flows. In connection with these flow augmentation efforts, the
Company has been cooperating with the federal agencies by moving and
shaping water acquired by the BOR through the HCC. In the past, the
Company has been reimbursed for any energy losses incurred as a
result of this cooperation through an agreement with the BPA. While
this agreement expired in April of 2001, the Company has advised
federal interests of its willingness to continue to assist with the
movement and shaping of federal flow augmentation water provided any
adverse impact to its customers is satisfactorily addressed.
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 listing as an issue
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.
During relicensing, the FERC is required by the Endangered Species
Act (Section 7) to consult with the USFWS. This consultation has
been requested by the FERC.
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. IPC has sufficient SO2 allowances to provide
compliance for all three coal-fired facilities and the Danskin
natural gas-fired facility. Therefore, we foresee no adverse
effects on our operations with regard to SO2 emissions.
New Accounting Pronouncements
In July 2001 the Financial Accounting Standards Board (FASB) issued
Statement of Financial Accounting Standards (SFAS) 141, "Business
Combinations," which addresses accounting and reporting for business
combinations. SFAS 141 requires that all business combinations
initiated after June 30, 2001 be accounted for using one method, the
purchase method. The adoption of SFAS 141 did not have a
significant effect on our financial statements.
Also in July 2001 the FASB issued SFAS 142, "Goodwill and Other
Intangible Assets," which is effective January 1, 2002. SFAS 142
changes the accounting for goodwill from an amortization method to
an impairment-only method. Thus, amortization of goodwill,
including goodwill recorded in past transactions, will cease. The
Company will be required to complete transitional goodwill
impairment tests within six months of the date of adoption, and at
least annually thereafter. The standard also includes provisions
for the reclassification of certain existing recognized intangibles
to goodwill, reassessment of the useful lives of existing recognized
intangibles and reclassification of certain intangibles out of
goodwill. The Company has a $13 million goodwill balance (net of
amortization) at December 31, 2001, and recorded amortization
expense of approximately $3 million in 2001. The Company will be
performing transitional impairment tests of its goodwill balances in
the first half of 2002.
In August 2001 the FASB issued SFAS 143, "Accounting for Asset
Retirement Obligations," which is effective for fiscal years
beginning after June 15, 2002. This Statement addresses financial
accounting and reporting for obligations associated with the
retirement of tangible long-lived assets and the associated asset
retirement costs. An obligation may result from the acquisition,
construction, development and the normal operation of a long-lived
asset. The Company is currently assessing but has not yet
determined the impact of SFAS 143 on our financial position and
results of operations.
Also in August 2001 the FASB issued SFAS 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets," which is effective for
fiscal years beginning after December 15, 2001. SFAS 144 addresses
financial accounting and reporting for the impairment or disposal of
long-lived assets, superseding SFAS 121, "Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to be
Disposed of." The Company is currently assessing but has not yet
determined the impact of SFAS 144 on its financial position and
results of operations.
Critical Accounting Policies
IPC follows SFAS 71, "Accounting for the Effects of Certain Types of
Regulation," and our financial statements reflect the effects of the
different rate making principles followed by the various
jurisdictions regulating IPC. The primary result of this policy is
that IPC has deferred $600 million of regulatory assets at December
31, 2001. Of this amount, $305 million relates to current year
power supply expenditures. While we expect to fully recover this
amount, such recovery is subject to final review by the regulatory
entities.
IE values its energy trading contracts using mark-to-market
accounting under Emerging Issue Task Force (EITF) 98-10 and SFAS
133. As explained previously in our discussion of energy marketing,
this accounting requires the Company to consider several factors,
including current relevant market prices, market depth and
liquidity, potential model error, and expected credit losses at the
counterparty level. Due to the volatility of energy markets and
certain model assumptions, changes in market conditions could
substantially change the amounts of gains or losses ultimately
realized in settlement of the contracts.
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
SCHEDULE
PAGE
Management's Responsibility for Financial Statements 41
Consolidated Financial Statements:
IDACORP, Inc.
Consolidated Statements of Income for the Years Ended
December 31, 2001, 2000 and 1999 43
Consolidated Balance Sheets as of December 31, 2001 and 2000 44-45
Consolidated Statements of Cash Flows for the Years Ended
December 31, 2001, 2000 and 1999 46
Consolidated Statement of Shareholders' Equity for the Years
Ended December 31, 2001, 2000 and 1999 47
Consolidated Statements of Comprehensive Income for the Years
Ended December 31, 2001, 2000 and 1999 48
Notes to Consolidated Financial Statements 49-69
Independent Auditors' Report 70
Supplemental Financial Information and Financial Statement
Schedule
Supplemental Financial Information (Unaudited) 71
Financial Statement Schedule for the Years Ended December 31,
2001, 2000 and 1999:
Schedule II-Consolidated Valuation and Qualifying Accounts 74
MANAGEMENT'S RESPONSIBILITY FOR FINANCIAL STATEMENTS
The management of IDACORP, Inc. 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 Company maintains systems of internal accounting controls and
related policies and procedures. The systems are designed to
provide reasonable assurance that all assets are protected against
loss or unauthorized use. Also, the systems provide that
transactions are executed in accordance with management's
authorization and properly recorded to permit preparation of
reliable financial statements. The systems are supported by a
staff of corporate accountants and internal auditors who, among
other duties, evaluate and monitor the systems of internal
accounting control in coordination with the independent auditors.
The staff of internal auditors conducts special and operational
audits in support of these accounting controls throughout the
year.
The Board of Directors, through its Audit Committee comprised
entirely of outside directors, meets periodically with management,
internal auditors and independent auditors to discuss auditing,
internal control and financial reporting matters. To ensure their
independence, both the internal auditors and independent auditors
have full and free access to the Audit Committee.
The financial statements have been audited by Deloitte & Touche
LLP, the Company's independent auditors, who were responsible for
conducting their audit in accordance with generally accepted
auditing standards.
Jan B. Packwood Darrel T. Anderson
President and Vice President, Chief
Chief Executive Financial Officer and
Officer Treasurer
IDACORP, Inc.
Consolidated Statements of Income
Year Ended December 31,
2001 2000 1999
(millions of dollars except for
per share amounts)
OPERATING REVENUES:
Electric utility:
General business $ 650 $ 565 $ 516
Off system sales 220 230 120
Other revenues 44 42 24
Total electric
utility revenues 914 837 660
Energy marketing
commodities and services 4,721 2,136 746
Other 13 23 27
Total operating
revenues 5,648 2,996 1,433
OPERATING EXPENSES:
Electric utility:
Purchased power 584 399 106
Fuel expense 98 94 87
Power cost adjustment (176) (121) (1)
Other operations and
maintenance 211 196 196
Depreciation 87 80 78
Taxes other than
income taxes 20 20 22
Total electric
utility expenses 824 668 488
Energy marketing:
Cost of energy
commodities and services 4,478 1,990 714
Selling, general and
administrative 66 51 10
Other 37 39 34
Total operating
expenses 5,405 2,748 1,246
OPERATING INCOME:
Electric utility 90 169 172
Energy marketing 177 95 22
Other (24) (16) (7)
Total operating income 243 248 187
OTHER INCOME 23 30 17
INTEREST EXPENSE AND
OTHER:
Interest on long-term
debt 56 53 54
Other interest 15 8 7
Preferred dividends of
Idaho Power Company 5 6 6
Total interest expense
and other 76 67 67
INCOME BEFORE INCOME
TAXES 190 211 137
INCOME TAXES 65 71 46
NET INCOME $ 125 $ 140 $ 91
AVERAGE COMMON SHARES
OUTSTANDING (000'S) 37,387 37,556 37,612
EARNINGS PER SHARE OF
COMMON STOCK (basic and
diluted) $ 3.35 $ 3.72 $ 2.43
The accompanying notes are an integral part of these statements.
IDACORP, Inc.
Consolidated Balance Sheets
December 31,
2001 2000
(millions of dollars)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents $ 67 $ 107
Receivables:
Customer 207 244
Allowance for uncollectible
accounts (43) (23)
Employee notes 6 5
Other 11 16
Energy marketing assets 194 1,060
Taxes receivable 51 -
Accrued unbilled revenues 37 45
Materials and supplies (at average
cost) 26 30
Fuel stock (at average cost) 9 5
Prepayments 32 24
Regulatory assets 56 9
Total current assets 653 1,522
INVESTMENTS 159 176
PROPERTY, PLANT AND EQUIPMENT:
Utility plant in service 2,990 2,800
Accumulated provision for
depreciation (1,220) (1,143)
Utility plant in service - net 1,770 1,657
Construction work in progress 96 136
Utility plant held for future use 2 2
Other property, net of accumulated
depreciation 18 9
Property, plant and equipment - net 1,886 1,804
OTHER ASSETS:
American Falls and Milner water
rights 31 31
Company-owned life insurance 40 40
Energy marketing assets - long-term 204 44
Regulatory assets 544 370
Long-term receivables 74 -
Other 51 53
Total other assets 944 538
TOTAL $ 3,642 $ 4,040
The accompanying notes are an integral part of these statements.
IDACORP, Inc
Consolidated Balance Sheets
December 31,
2001 2000
(millions of dollars)
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES:
Current maturities of long-term debt $ 36 $ 40
Notes payable 363 121
Accounts payable 248 272
Energy marketing liabilities 125 1,060
Derivative liabilities 41 -
Taxes accrued - 16
Interest accrued 15 17
Deferred income taxes 24 9
Other 55 28
Total current liabilities 907 1,563
OTHER LIABILITIES:
Deferred income taxes 590 461
Energy marketing liabilities - long-
term 135 47
Derivative liabilities - long-term 7 -
Regulatory liabilities 114 111
Other 71 68
Total other liabilities 917 687
LONG-TERM DEBT 843 864
COMMITMENTS AND CONTINGENT LIABILITIES
PREFERRED STOCK OF IDAHO POWER COMPANY 104 105
SHAREHOLDERS' EQUITY:
Common stock, no par value (shares
authorized 120,000,000;
37,628,919 and 37,612,351 shares
issued, respectively) 454 453
Retained earnings 424 370
Accumulated other comprehensive
income (loss) (4) (1)
Treasury stock (66,188 and 44,425
shares at cost, respectively) (3) (1)
Total shareholders' equity 871 821
TOTAL $ 3,642 $ 4,040
The accompanying notes are an integral part of these statements.
IDACORP, Inc.
Consolidated Statements of Cash Flows
Year Ended December 31,
2001 2000 1999
(millions of dollars)
OPERATING ACTIVITIES:
Net income $ 125 $ 140 $ 91
Adjustments to reconcile net
income to net cash provided
by (used in) operating
activities:
Allowance for uncollectible
accounts 20 22 -
Unrealized (gains) losses from
energy marketing activities (93) 35 (4)
Gain on sales of assets (2) (14) -
Depreciation and amortization 111 104 95
Deferred taxes and investment
tax credits 150 47 (2)
Accrued PCA costs (185) (122) (1)
Change in:
Receivables and prepayments 33 (179) 3
Accrued unbilled revenues 8 (13) 3
Materials and supplies and
fuel stock - 4 (2)
Accounts payable 4 126 44
Taxes (receivable) accrued (67) (6) (3)
Other current assets and
liabilities (50) (2) 5
Long-term receivable (74) - -
Other - net 12 (8) 1
Net cash provided by (used
in) operating activities (8) 134 230
INVESTING ACTIVITIES:
Additions to property, plant
and equipment (180) (140) (111)
Investments in affordable
housing projects - (29) (19)
Proceeds from sales of assets 12 17 -
Other - net (3) (1) (11)
Net cash used in investing
activities (171) (153) (141)
FINANCING ACTIVITIES:
Proceeds from issuance of:
First mortgage bonds 120 80 80
Other long-term debt - 14 19
Retirement of:
First mortgage bonds (130) (80) -
Other long-term debt (14) (22) (10)
Dividends on common stock (70) (70) (70)
Increase (decrease) in short-
term borrowings 242 101 (19)
Common stock issued 1 - -
Distributions of treasury stock 3 - -
Acquisition of treasury stock (8) (8) -
Other - net (5) - (1)
Net cash provided by (used
in) financing activities 139 15 (1)
Net increase (decrease) in cash
and cash equivalents (40) (4) 88
Cash and cash equivalents
beginning of period 107 111 23
Cash and cash equivalents at end
of period $ 67 $ 107 $ 111
SUPPLEMENTAL DISCLOSURE OF CASH
FLOW INFORMATION:
Cash paid (received) during the
year for:
Income taxes $ (18) $ 30 $ 52
Interest (net of amount
capitalized) $ 70 $ 62 $ 56
Distributions of treasury stock
for acquisition $ 8 $ 2 $ -
The accompanying notes are an integral part of these statements.
IDACORP, Inc.
Consolidated Statements of Shareholders' Equity
Accumulated
Other
Common Stock Retained Comprehenisve Treasury Stock Total
Shares Amount Earnings Income (Loss) Share Amount Amount
(millions of dollars except share amounts which are in thousands)
Balance at
January 1,
1998 37,612 $452 $ 279 $ - - $ - $731
Net income - - 91 - - - 91
Common stock
dividends - - (70) - - - (70)
Unrealized
gain on
securities
(net of tax) - - - 1 - - 1
Balance at
December 31,
1999 37,612 452 300 1 - - 753
Net income - - 140 - - - 140
Common stock
dividends - - (70) - - - (70)
Issued - - - - (155) 7 7
Acquired - - - - 199 (8) (8)
Other - 1 - - - - 1
Unrealized
loss on
securities
(net of tax) - - - (2) - - (2)
Balance at
December 31,
2000 37,612 453 370 (1) 44 (1) 821
Net income - - 125 - - - 125
Common stock
dividends - - (70) - - - (70)
Issued 17 1 - - (292) 11 12
Acquired - - - - 314 (13) (13)
Other - - (1) - - - (1)
Unrealized
loss on
securities
(net of tax) - - - (2) - - (2)
Minimum
pension
liability
adjustment
(net of tax) - - - (1) - - (1)
Balance at
December 31,
2001 37,629 $454 $ 424 $ (4) 66 $ (3) $871
The accompanying notes are an integral part of these statements.
IDACORP, Inc.
Consolidated Statements of Comprehensive Income
Year Ended December 31,
2001 2000 1999
(millions of dollars)
NET INCOME $ 125 $ 140 $ 91
OTHER COMPREHENSIVE INCOME (LOSS):
Unrealized gains (losses) on
securities (net of tax of ($1),
($2) and $1) (2) (2) 1
Minimum pension liability
adjustment (net of tax of ($1)) (1) - -
TOTAL COMPREHENSIVE INCOME $ 122 $ 138 $ 92
The accompanying notes are an integral part of these statements
IDACORP, Inc.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
Nature of Business
IDACORP, Inc. (IDACORP or the Company) is a holding company whose
principal operating subsidiaries are Idaho Power Company (IPC) and
IDACORP Energy (IE). IPC is regulated by the Federal Energy
Regulatory Commission (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. IE markets electricity and natural gas, and
offers risk management and asset optimization services, to wholesale
customers in 31 states and two Canadian provinces.
IDACORP's other subsidiaries include:
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;
Velocitus - commercial and residential Internet service
provider;
IDACOMM - provider of telecommunications services.
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
Principles of Consolidation
The consolidated financial statements include the accounts of the
Company and wholly-owned or controlled subsidiaries. All
significant intercompany 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 expensed to
operations. The Company records repair and maintenance costs
associated with planned major maintenance as these costs are
incurred. At IPC 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)
AFDC, a non-cash item, represents the composite interest costs of
debt, and a return on equity funds, used to finance utility
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 2001, 2000 and 1999 were 5.4 percent,
8.3 percent, and 7.8 percent, respectively. IPC's total reductions
to interest expense for AFDC were $4 million, $2 million and $1
million, and other income included $1 million, $3 million and $2
million for 2001, 2000 and 1999, 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.
IE reports marketing and trading revenues and expenses on a gross
basis. The Company has reclassified revenues and expenses for prior
years to conform to the current presentation. Within revenues there
are three classifications. The first is the mark-to-market, or
unrealized, gains or losses recorded as a result of reporting
forward contracts at fair value. The change in the fair value of
all forward energy transactions (purchases and sales) are netted and
reported as one revenue amount. This revenue item may be positive
or negative in any given reporting period. The second
classification is settled financial transactions. Financial
transactions, on settlement, are valued as either "in" or "out" of
the money (positive or negative value) and the net cash is either
received from or paid to the corresponding counterparty. These
transactions also are netted within revenue and can be either
positive or negative in any reporting period. The third
classification is settled physical deals. Settled physical sales
transactions are reported as revenue and settled physical purchases
are reported as operating expenses. Other cost of sales items such
as transmission and broker fees are reported as operating expenses.
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 electricity and natural gas
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
Emerging Issue Task Force (EITF) 98-10, "Accounting for Contracts
Involved in Energy Trading Activities," and Statement of Financial
Accounting Standard (SFAS) 133, "Accounting for Derivative
Instruments and Hedging Activities" as amended by SFAS 138
"Accounting for Certain Derivative Instruments and Certain Hedging
Activities."
Power Cost Adjustment (PCA)
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 in May, are based on
forecasts of net power supply expenses and the true-up of the prior
year's forecast. During the year, the difference between the actual
and forecasted costs is deferred with interest. The balance of this
deferral, called a true-up, is then included in the calculation of
the next year's PCA adjustment.
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 2.98 percent in 2001 and 2.94 percent
in 2000 and 1999.
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 Idaho Public Utility Commission
(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's 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.
Earnings Per Share (EPS)
The computation of diluted EPS differs from basic EPS only due to
including potentially dilutive shares related to stock-based
compensation awards. The diluted EPS calculation includes
immaterial amounts of potentially dilutive shares for the periods
presented.
The diluted EPS computation for 2001 excluded 274,000 common stock
options because the options' exercise price was greater than the
average market price of the common stock. The options, which expire
in 2011, were still outstanding at the end of 2001. There were no
such options excluded from the diluted EPS calculation in 2000 and
1999.
Stock-Based Compensation
SFAS 123, "Accounting for Stock-Based Compensation" encourages a
fair-value based method of accounting for stock-based compensation.
As permitted by SFAS 123, the Company adopted the disclosure-only
requirements and continues to account for stock-based compensation
in accordance with the provisions of Accounting Principles Board
Opinion 25, "Accounting for Stock Issued to Employees" (APB 25), as
interpreted by Financial Accounting Standards Board (FASB)
Interpretation 44 "Accounting for Certain Transactions Involving
Stock Compensation," and various EITF issues.
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.
Investments
IFS invests in affordable housing projects that are accounted for in
accordance with EITF 94-1 "Accounting for Tax Benefits Resulting
from Investments in Affordable Housing Projects" and shown in the
caption "Investments" on the balance sheet. IFS accounts for these
investments using the equity method. All projects are reviewed
periodically for impairment. At December 31, 2001 and 2000 the net
affordable housing projects included in investments were $95 and
$102 million.
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
IPC follows SFAS 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. The economic effects of regulation
can result in regulated companies recording costs that have been or
are expected to be allowed in the ratemaking process in a period
different from the period in which the costs would be charged to
expense by an unregulated enterprise. When this occurs, costs are
deferred as assets in the balance sheet (regulatory assets) and
recorded as expenses in the periods when those same amounts are
reflected in rates. Additionally, regulators can impose liabilities
upon a regulated company for amounts previously collected from
customers and for amounts that are expected to be refunded to
customers (regulatory liabilities).
Comprehensive Income
Components of the Company's comprehensive income include net income,
unrealized holding gains (losses) on marketable securities, the
Company's proportionate share of unrealized holding gains (losses)
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 July 2001 the FASB issued SFAS 141, "Business Combinations,"
which addresses accounting and reporting for business combinations.
SFAS 141 requires that all business combinations initiated after
June 30, 2001 be accounted for using one method, the purchase
method. The adoption of SFAS 141 did not have a significant effect
on the Company's financial statements.
Also in July 2001 the FASB issued SFAS 142, "Goodwill and Other
Intangible Assets," which is effective January 1, 2002. SFAS 142
changes the accounting for goodwill from an amortization method to
an impairment-only method. Thus, amortization of goodwill,
including goodwill recorded in past transactions, will cease. The
Company will be required to complete transitional goodwill
impairment tests within six months of the date of adoption, and at
least annually thereafter. The standard also includes provisions
for the reclassification of certain existing recognized intangibles
to goodwill, reassessment of the useful lives of existing recognized
intangibles and reclassification of certain intangibles out of
goodwill. The Company has a $13 million goodwill balance (net of
amortization) at December 31, 2001 and recorded amortization expense
of approximately $3 million in 2001. The Company will be performing
transitional impairment tests of its goodwill balances in the first
half of 2002.
In August 2001 the FASB issued SFAS 143, "Accounting for Asset
Retirement Obligations," which is effective for fiscal years
beginning after June 15, 2002. This Statement addresses financial
accounting and reporting for obligations associated with the
retirement of tangible long-lived assets and the associated asset
retirement costs. An obligation may result from the acquisition,
construction, development and the normal operation of a long-lived
asset. The Company is currently assessing but has not yet
determined the impact of SFAS 143 on its financial position and
results of operations.
Also in August 2001 the FASB issued SFAS 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets," which is effective for
fiscal years beginning after December 15, 2001. SFAS 144 addresses
financial accounting and reporting for the impairment or disposal of
long-lived assets, superseding SFAS 121, "Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to be
Disposed of." The Company is currently assessing but has not yet
determined the impact of SFAS 144 on its financial position and
results of operations.
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 2001 have been
reclassified to conform to the current year's presentation. Net
income and shareholders' equity were not affected by these
reclassifications.
2. INCOME TAXES:
The Company has settled Federal and Idaho tax liabilities on all
open years through the 1997 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:
2001 2000 1999
(millions of dollars)
Computed income taxes based
on statutory federal income
tax rate $ 67 $ 74 $ 48
Change in taxes resulting
from:
AFDC (2) (2) (1)
Investment tax credits (3) (3) (3)
Repair allowance (3) (4) (3)
Settlement of prior years
tax returns (1) - -
State income taxes (net of
federal reduction) 8 9 6
Depreciation 10 8 7
Affordable housing and
historic tax credits (net
of related deferred
taxes) (13) (13) (9)
Preferred dividends of IPC 2 2 2
Other - - (1)
Total provision for federal
and state income taxes $ 65 $ 71 $ 46
Effective tax rate 34.2% 33.6% 33.6%
The provision for income taxes consists of the following:
2001 2000 1999
(millions of dollars)
Income taxes currently
(receivable) payable:
Federal $ (67) $ 19 $ 38
State (18) 5 10
Total (85) 24 48
Income taxes deferred -
net of amortization:
Federal 122 41 2
State 26 7 (2)
Total 148 48 -
Investment tax credits:
Deferred 5 2 1
Restored (3) (3) (3)
Total 2 (1) (2)
Total provision for income
taxes $ 65 $ 71 $ 46
The tax effects of significant items comprising the Company's net
deferred tax liability are as follows:
2001 2000
(millions of dollars)
Deferred tax assets:
Regulatory liabilities $ 41 $ 40
Advances for construction 4 9
Other 17 24
Total 62 73
Deferred tax liabilities:
Utility plant 250 250
Regulatory assets 210 214
Conservation programs 11 14
PCA 119 47
Net energy trading assets 72 1
Other 14 17
Total 676 543
Net deferred tax liabilities $614 $470
3. COMMON STOCK:
As of December 31, 2001 there were 4,274,753 shares of authorized
but unissued shares of IDACORP common stock 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 2,050,000
shares for the Long-Term Incentive and Compensation Plan (LTICP)
(see Note 9).
In 2001 the Company acquired 198,200 shares of outstanding common
stock, at a cost of $8 million, for potential distribution to
shareholders of an acquired entity as partial payment for the
acquisition. In 2000 the Company acquired 156,300 shares at a cost
of $7 million for the same purpose. The Company has issued 226,684
shares to the shareholders of the acquired entity. An additional
65,416 shares are contingently issuable over the next three years.
Of the remaining acquired shares, 61,628 were issued in connection
with our dividend reinvestment program.
The Company issued 16,568 original issue shares in 2001 for the
Employee Savings Plan (see Note 10).
The Company has a Shareholder Rights Plan (Plan) designed to ensure
that all shareholders receive fair and equal treatment in the event
of any proposal to acquire control of the Company. Under the Plan,
the Company declared a distribution of one Preferred Share Purchase
Right (Right) for each of the Company's outstanding Common Shares
held on October 1, 1998 or issued thereafter. The Rights are
currently not exercisable and will be exercisable only if a person
or group (Acquiring Person) either acquires ownership of 20 percent
or more of the Company's Voting Stock or commences a tender offer
that would result in ownership of 20 percent or more of such stock.
The Company may redeem all but not less than all of the Rights at a
price of $0.01 per Right or exchange the Rights for cash, securities
(including Common Shares of the Company) or other assets at any time
prior to the close of business on the 10th day after acquisition by
an Acquiring Person of a 20 percent or greater position.
Additionally, the IDACORP Board created the A Series Preferred
Stock, without par value, and reserved 1,200,000 shares for issuance
upon exercise of the Rights.
Following the acquisition of a 20 percent or greater position, each
Right will entitle its holder to purchase for $95 that number of
shares of Common Stock or Preferred Stock having a market value of
$190.
If after the Rights become exercisable, the Company is acquired in a
merger or other business combination, 50 percent or more of its
consolidated assets or earnings power are sold, or the Acquiring
Person engages in certain acts of self-dealing, each Right entitles
the holder to purchase for $95, shares of the acquiring company's
common stock having a market value of $190.
Any Rights that are or were held by an Acquiring Person become void
if any of these events occurs. The Rights expire on September 30,
2008.
The Rights themselves do not give any voting or other rights as
shareholders to their holders. The terms of the Rights may be
amended without the approval of any holders of the Rights until an
Acquiring Person obtains a 20 percent or greater position, and then
may be amended as long as the amendment is not adverse to the
interests of the holders of the Rights.
4. PREFERRED STOCK OF IDAHO POWER COMPANY:
The number of shares of IPC preferred stock outstanding at December
31, 2001 and 2000 were as follows:
Shares
Outstanding at
December 31, Call Price
2001 2000 Per Share
Preferred stock:
Cumulative, $100 par value:
4% preferred stock
(authorized 215,000 shares) 143,872 150,656 $104.00
Serial preferred stock, 7.68%
Series (authorized 150,000
shares) 150,000 150,000 $102.97
Serial preferred stock,
cumulative, without par
value; total of 3,000,000
shares authorized:
7.07% Series, $100
stated value (authorized
250,000 shares)(a) 250,000 250,000 $103.535 to $100.354
Auction rate preferred
stock, $100,000 stated
value (authorized 500
shares) (b) 500 500
Total 544,372 551,156
(a) The preferred stock is not redeemable prior to July 1, 2003.
(b) Dividend rate at December 31, 2001 was 3.65% and ranged between
3.12% and 4.95% during the year.
During 2001 and 2000 IPC reacquired and retired 6,784 and 7,456
shares, of 4% preferred stock. As of December 31, 2001, the overall
effective cost of all outstanding preferred stock was 5.13 percent.
5. LONG-TERM DEBT:
The following table summarizes long-term debt at December 31:
2001 2000
(millions of dollars)
First mortgage bonds:
6.93% Series due 2001 $ - $ 30
6.85% Series due 2002 27 27
6.40% Series due 2003 80 80
8 % Series due 2004 50 50
5.83% Series due 2005 60 60
7.38% Series due 2007 80 80
7.20% Series due 2009 80 80
6.60% Series due 2011 120 -
Maturing 2021 through 2027
with rates ranging from
7.5% to 8.75% 130 230
Total first mortgage bonds 627 637
Pollution control revenue
bonds:
8.30% Series 1984 due 2014 50 50
6.05% Series 1996A due 2026 68 68
Variable Rate Series 1996B
due 2026 24 24
Variable Rate Series 1996C
due 2026 24 24
Variable Rate Series 2000 due
2027 4 4
Total pollution control
revenue bonds 170 170
REA notes 1 1
American Falls bond guarantee 20 20
Milner Dam note guarantee 12 12
Unamortized premium/discount -
net (1) (1)
Debt related to investments in
affordable housing 50 64
Other subsidiary debt - 1
Total 879 904
Less current maturities of long-
term debt (36) (40)
Total long-term debt $ 843 $ 864
At December 31, 2001, the maturities for the aggregate amount of
long-term debt outstanding were (in millions of dollars):
Unregulated
Utility Business
2002 $ 27 $ 9
2003 80 9
2004 50 9
2005 60 8
2006 - 6
Thereafter 612 9
Total $829 $ 50
The Company currently has a $300 million shelf registration
statement that can be used for the issuance of unsecured debt
(including medium-term notes) and preferred or common stock. At
December 31, 2001, none had been issued.
On March 23, 2000, IPC filed a $200 million shelf registration
statement that could be used for First Mortgage Bonds (including
medium term notes), unsecured debt, or preferred stock. On December
1, 2000, IPC issued $80 million principal amount of Secured Medium-
Term Notes, Series C, 7.38% Series due 2007. Proceeds were used for
the early redemption in January 2001 of the $75 million First
Mortgage Bonds 9.50% Series due 2021. On March 2, 2001, IPC issued
$120 million principal amount of Secured Medium-Term Notes, Series
C, 6.60% Series due 2011 with the proceeds used to reduce short-term
borrowing incurred in support of ongoing long-term construction
requirements. At December 31, 2001, no amount remained to be
issued on this shelf registration statement.
On August 16, 2001, IPC filed a $200 million shelf registration
statement that can be used for First Mortgage Bonds (including
medium-term notes), unsecured debt or preferred stock. At December
31, 2001, no amounts had been issued.
In August 2001, $25 million First Mortgage Bonds 9.52% Series due
2031 were redeemed early.
The amount of first mortgage bonds issuable by IPC is limited to a
maximum of $900 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.
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 $20
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 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, 2001 and 2000 the overall effective cost of all
outstanding first mortgage bonds and pollution control revenue bonds
was 7.0 percent and 7.52 percent, respectively.
At December 31, 2001, IFS has $50 million of debt with interest
rates ranging from 6.03 percent to 8.59 percent due 2002 to 2011.
This debt is collateralized by investments in affordable housing
projects with a book value of $95 million at December 31, 2001.
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 notes receivable,
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 $920 million in 2001 and $934 million in 2000.
Included in receivables were notes totaling $16 million in 2001 and
$12 million in 2000. Estimated fair value of these instruments was
$17 million in 2001 and $13 million in 2000. Included in
investments and other property were financial instruments totaling
$34 million in 2001 and $35 million in 2000. Estimated fair value
of these instruments was $34 million in 2001 and $40 million in
2000.
7. NOTES PAYABLE:
At December 31, 2001, IDACORP has a $375 million facility that
expires April 15, 2002, and a $50 million facility that expires
April 20, 2002. Under these facilities the Company pays a facility
fee on the commitment, quarterly in arrears, based on IDACORP's
senior unsecured long-term debt rating. Commercial paper may be
issued up to the amounts supported by the bank credit facilities.
At December 31, 2001, IPC had regulatory authority to incur up to
$500 million of short-term indebtedness. IPC has a $165 million
facility that expires April 26, 2002 and a $120 million facility
that expires April 18, 2002. Under these facilities IPC pays a
facility fee on the commitment, quarterly in arrears, based on IPC's
First Mortgage Bond Rating. IPC's commercial paper may be issued up
to the amounts supported by the bank credit facilities.
At December 31, 2001, IPC also had $100 million of floating rate
notes outstanding, payable on September 1, 2002.
Balances and interest rates of short-term borrowings were as follows
at December 31 (in millions of dollars):
2001 2000
IDACORP balance at end of year $ 81 $ 61
IPC balance at end of year $ 282 $ 60
Combined effective annual
interest rate at end of year 2.18% 6.74%
8. COMMITMENTS AND CONTINGENT LIABILITIES:
Commitments under contracts and purchase orders relating to IPC's
and Ida-West's program for construction and operation of facilities
amounted to approximately $9 million and $30 million, respectively,
at December 31, 2001. The commitments are generally revocable by
the Company 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 year ended December
31, 2001, IPC purchased 728,155 MWh at a cost of $45 million.
Legal Proceedings
IE filed a lawsuit on November 30, 2001 in Idaho State District
Court in and for the County of Ada against Overton Power District
No. 5 (Overton), a Nevada Electric Improvement District, for failure
to meet payment obligations under a power contract. The contract
provided for Overton to purchase 40 megawatts of electrical energy
per hour from IE at $88.50 per megawatt hour, from July 1, 2001
through June 30, 2011. In the contract, Overton agreed to raise its
rates to its customers to the extent necessary to make its payment
obligations to IE under the contract. IE has asked the Idaho
District Court for damages pursuant to the contract, for a
declaration that Overton is not entitled to renegotiate or terminate
the contract and for injunctive relief requiring Overton to raise
rates as agreed.
On December 14, 2001, IE notified Overton that the contract was
terminated due to their failure to meet payment obligations.
IE believes that Overton's breach of contract is completely without
basis and intends to vigorously prosecute this lawsuit. While the
outcome of litigation is never certain, IE believes it should
prevail on the merits. At December 31, 2001, the Company had a $74
million long-term asset related to the Overton claim. IE will
review the recoverability of the asset on an ongoing basis.
From time to time the Company is party to various legal claims,
actions, and complaints, certain of which may involve material
amounts. Although the Company is unable to predict with certainty
whether or not it will ultimately be successful in these legal
proceedings, or, if not, what the impact might be, based upon the
advice of legal counsel, management presently believes that
disposition of these matters will not have a material adverse effect
on the Company's financial position, results of operation, or cash
flows.
California Energy Situation
As a component of IPC's 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, at this time,
operated a wholesale electricity market in California by acting as a
clearinghouse through which electricity was bought and sold.
Pursuant to the participation agreement, IPC could sell power to the
CalPX under the terms and conditions of the CalPX Tariff. Under the
participation agreement, if a participant in the CalPX exchange
defaults on a payment to the exchange, the other participants are
required to pay their allocated share of the default amount to the
exchange. The allocated shares are based upon the level of trading
activity, which includes both power sales and purchases, of each
participant during the preceding three-month period.
On January 18, 2001, the CalPX sent IPC 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. IPC made this payment. On January 24, 2001, IPC
terminated the participation agreement. On February 8, 2001, the
CalPX sent a further invoice for $5.2 million, due February 20,
2001, as a result of alleged payment defaults by SCE, Pacific Gas
and Electric Company (PG&E), and others. However, because the CalPX
owed IPC $11.3 million for power sold to the CalPX in November and
December 2000, IPC did not pay the February 8th invoice. IPC
essentially discontinued energy trading with California entities in
December 2000.
IPC believes that the default invoices were not proper and that IPC
owes no further amounts to the CalPX. IPC has pursued all available
remedies in its efforts to collect amounts owed to it by the CalPX.
On February 20, 2001, IPC filed a petition with FERC to intervene in
a proceeding which requested the FERC to suspend the use of the
CalPX charge back methodology and provides for further oversight in
the CalPX's implementation of its default mitigation procedures.
A preliminary injunction was 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.
In April 2001, PG&E filed for bankruptcy. The CalPX and the
California Independent System Operator (Cal ISO) were among the
creditors of PG&E. To the extent that PG&E's bankruptcy filing
affects the collectibility of the receivables from the CalPX and Cal
ISO the receivables from these entities are at greater risk.
Also in April 2001, the FERC issued an order stating that it was
establishing price mitigation for sales in the California wholesale
electricity market. Subsequently, in its June 19, 2001 Order, the
FERC expanded that price mitigation plan to the entire western
United States electrically interconnected system. That plan
included the potential for orders directing electricity sellers into
California since October 2, 2000 to refund portions of their sales
prices if the FERC determined that those prices were not just and
reasonable, and therefore not in compliance with the Federal Power
Act. The June 19th Order also required all buyers and sellers in
the Cal ISO market during the subject time-frame to participate in
settlement discussions to explore the potential for resolution of
these issues without further FERC action. The settlement
discussions failed to bring resolution of the refund issue and as a
result, the FERC Chief Judge submitted a Report and Recommendation
to the FERC recommending that the FERC adopt the methodology set
forth in the report and set for evidentiary hearing an analysis of
the Cal ISO's and the CalPX's spot markets to determine what refunds
may be due upon application of that methodology. The Judge
recommended that the methodology should be applied to all sellers
except those who at the evidentiary hearing are able to demonstrate
that their costs exceed the results of the recommended methodology.
On July 25, 2001, the FERC issued an order establishing evidentiary
hearing procedures related to the scope and methodology for
calculating refunds related to transactions in the spot markets
operated by the Cal ISO and the CalPX during the period October 2,
2000 through June 20, 2001. As to potential refunds, if any, the
Company believes that its exposure will be more than offset by
amounts due it from California entities.
In addition, the July 25, 2001 FERC order established another
proceeding to explore whether there may have been unjust and
unreasonable charges for spot market sales in the Pacific Northwest
during the period December 25, 2000 through June 20, 2001. The FERC
Administrative Law Judge (ALJ) submitted recommendations and
findings to the FERC on September 24, 2001. The ALJ found that the
prices were just and reasonable and therefore no refunds should be
allowed. Procedurally, the ALJ's decision is a recommendation to
the commissioners of the FERC. Multiple parties have filed requests
for rehearing and petitions for review. The ALJ has re-established
a procedural schedule which would result in findings of fact and
recommended conclusions during August 2002; such schedule is subject
to Commission review.
Effective June 11, 2001, IPC transferred its non-utility wholesale
electricity marketing operations to IE. Effective with the June 11
transfer, the outstanding receivables and payables with the CalPX
and Cal ISO were assigned from IPC to IE. At December 31, 2001, the
CalPX and Cal ISO owed $13 million and $31 million, respectively,
for energy sales made to them by IPC in November and December 2000.
IE has accrued a reserve of $41 million against these receivables.
These reserves were calculated taking into account the uncertaintity
of collection, given the current California energy situation. Based
on the reserves recorded as of December 31, 2001, the Company
believes that the future collectibility of these receivables or any
potential refunds ordered by the FERC would not have a significant
impact on the Company's financial position, results of operations or
cash flows.
9. STOCK-BASED COMPENSATION:
The Company has two stock-based compensation plans that are intended
to align employee and shareholder objectives related to the long-
term growth of the Company.
The Company adopted the 2000 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 2,050,000.
In 2000 and 2001, the Company issued a total of 494,000 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 ratably over a five-year period.
In accordance with APB 25, no compensation costs have been
recognized for the option awards.
Stock option transactions are summarized as follows:
2001 2000
Weighted Weighted
Number average Number average
of exercise of exercise
shares price shares price
Outstanding
beginning of year 220,000 $ 35.81 - $ -
Granted 274,000 39.37 220,000 35.81
Exercised - - - -
Cancelled - - - -
Outstanding end
of year 494,000 $ 37.79 220,000 $35.81
Exercisable 44,000 $ 35.81 - $ -
The outstanding options had a range of exercise prices from $35.81
to $40.31. As of December 31, 2001, the weighted average remaining
contractual life is 8.9 years.
The Company also 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, 2001 there were 245,989 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 2001,
2000 and 1999, total compensation accrued under the plan was less
than $1 million for each year.
The following table summarizes restricted stock activity for the
years 2001, 2000 and 1999:
2001 2000 1999
Shares outstanding -
beginning of year 53,555 43,615 43,063
Shares granted 23,529 34,649 23,497
Shares forfeited (474) - (9,585)
Shares issued (19,918) (24,709) (13,360)
Shares outstanding - end of
year 56,692 53,555 43,615
Weighted average fair
value of current year
stock grants on grant
date $40.56 $34.44 $32.88
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 (in millions of dollars except for per share amounts):
2001 2000 1999
Net income
As reported $ 125 $ 140 $ 91
Pro forma 124 140 91
Basic and diluted earnings
per share
As reported $ 3.35 $ 3.72 $ 2.43
Pro forma 3.33 3.73 2.43
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 was estimated at the date of grant using the
Binomial option-pricing model with the following assumptions:
2001 2000
Stock dividend yield 4.72% 5.19%
Expected stock
price volatility 29% 27%
Risk-free interest rate 5.18% 6.15%
Expected option lives 7 years 7 years
Weighted average fair
value of options granted $9.86 $8.42
10. BENEFIT PLANS:
Pension Plans
The Company 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 2001, 2000 and 1999. The trustee invests the plan
assets primarily in listed stocks (both U.S. and foreign), fixed
income securities and investment grade real estate.
The Company 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:
Deferred
Pension Plan Compensation Plan
2001 2000 1999 2001 2000 1999
(in millions of dollars)
Service cost $ 8 $ 7 $ 8 $ - $ - $ -
Interest cost 18 17 16 2 2 2
Expected return on
assets (30) (30) (25) - - -
Recognized net
actuarial (gain)
loss (3) (4) - - - -
Amortization of
prior service cost - - 1 - - -
Amortization of
transition asset - - - 1 1 1
Net periodic
pension (benefit)
cost $ (7) $ (10) $ - $ 3 $ 3 $ 3
The following table summarizes the changes in benefit obligation and
plan assets of these plans (in millions of dollars):
Deferred
Pension Plan Compensation Plan
2001 2000 2001 2000
Change in projected
benefit obligation:
Benefit obligation at
January 1 $ 241 $ 229 $ 28 $ 27
Service cost 8 7 - -
Interest cost 18 17 2 2
Actuarial loss (gain) 19 - - 1
Benefits paid (13) (12) (2) (2)
Plan amendments - - 2 -
Benefit obligation at
December 31 273 241 30 28
Change in plan assets:
Fair value at January 1 341 340 - -
Actual return on plan
assets (2) 13 - -
Employer contributions - - - -
Benefit payments (13) (12) - -
Fair value at December
31 326 341 - -
Funded status 53 100 (30) (28)
Unrecognized actuarial
loss (gain) (32) (86) 8 7
Unrecognized prior
service cost 8 8 - -
Unrecognized net
transition liability (1) (1) 2 2
Net amount recognized $ 28 $ 21 $ (20) $ (19)
Amounts recognized in
the statement of
financial position
consist of:
Prepaid (accrued)
pension cost $ 28 $ 21 $ (29) $ (26)
Intangible asset - - 2 2
Accumulated other
comprehensive income - - 7 5
Net amount recognized $ 28 $ 21 $ (20) $ (19)
The following table sets forth the assumptions used at the end of
each year for all IPC-sponsored pension and postretirement benefit
plans:
Pension Postretirement
Benefits Benefits
2001 2000 2001 2000
Discount rate 7.0% 7.5% 7.0% 7.5%
Expected long-term rate of
return on assets 9.0 9.0 9.0 9.0
Annual salary increases 4.5 4.5 - -
Employee Savings Plan
The Company 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 $4
million in 2001 and $3 million in 2000 and 1999.
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
millions of dollars):
2001 2000 1999
Service cost $ 1 $ 1 $ 1
Interest cost 3 3 3
Expected return on plan assets (2) (2) (2)
Amortization of unrecognized
transition obligation 2 2 2
Amortization of prior service
cost (1) (1) (1)
Amortization of unrecognized
net gains - - -
Net periodic post-retirement
benefit cost $ 3 $ 3 $ 3
The following table summarizes the changes in benefit obligation and
plan assets (in millions of dollars):
2001 2000
Change in accumulated benefit
obligation:
Benefit obligation at January 1 $ 49 $ 41
Service cost 1 1
Interest cost 3 3
Plan amendments 1 1
Actuarial loss 3 6
Benefits paid (3) (3)
Benefit obligation at December 31 54 49
Change in plan assets:
Fair value of plan assets at
January 1 26 27
Actual (loss) return on plan
assets (2) (1)
Employer contributions 4 3
Benefits paid (3) (3)
Fair value of plan assets at
December 31 25 26
Funded status (29) (23)
Unrecognized prior service cost (6) (7)
Unrecognized actuarial loss (gain) 11 3
Unrecognized transition obligation 23 25
Accrued benefit obligations
included with other deferred credits $ (1) $ (2)
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 millions of dollars):
1-Percentage- 1-Percentage-
Point Point
increase decrease
Effect on total of service and
interest cost components $ - $ -
Effect on accumulated
postretirement benefit obligation $ 3 $ (3)
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 at December 31
(in millions of dollars):
2001 2000
Included with regulatory assets $ 1 $ 2
Included with other deferred
credits $(3) $(3)
11. UTILITY PLANT IN SERVICE AND JOINTLY-OWNED PROJECTS:
The following table sets out the major classifications of IPC's
utility plant in service, accumulated provision for depreciation and
annual depreciation provisions as a percent of average depreciable
balance (in millions of dollars):
2001 2000
Balance Avg Balance Avg
Rate Rate
Production $ 1,425 2.58% $ 1,360 2.60%
Transmission 460 2.30 410 2.30
Distribution 854 3.34 812 3.34
General and Other 251 6.12 218 5.42
Total in service 2,990 2.98% 2,800 2.94%
Accumulated provision
for depreciation (1,220) (1,143)
In service - net $ 1,770 $ 1,657
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's participation as of December 31, 2001 are as
follows:
Company Ownership
Accumulated
Utility Provision
Plant In for
Name of Plant Location Service Depreciation % MW
(millions of dollars)
Jim Bridger
Units 1-4 Rock Springs, WY $ 404 $ 222 33 707
Boardman Boardman, OR 65 38 10 55
Valmy Units 1
and 2 Winnemucca, NV 304 157 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 million in
2001, $44 million in 2000 and $42 million in 1999.
IPC has contracts to purchase the energy from four Public Utilities
Regulatory Policy Act Qualified Facilities that are 50 percent owned
by Ida-West. Power purchased from these facilities amounted to $6
million in 2001, $8 million in 2000 and $9 million in 1999.
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.
The Energy Marketing segment reflects the results of the operations
of IE. IE markets electricity and natural gas and offers risk
management and asset optimization services, to wholesale customers
in 31 states and two Canadian provinces.
IDACORP's other operations include:
Ida-West - independent power projects development and
management;
IdaTech - developer of integrated fuel cell systems;
IDACORP Financial Services (IFS) - affordable housing and other
real estate investments;
Velocitus - commercial and residential Internet service
provider;
IDACOMM - provider of telecommunications services.
The following table summarizes the segment information for the
Company's utility operations 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
(millions of dollars)
2001
Revenues from external
customers $ 821 $4,721 $ 13 $ - $5,555
Intersegment revenues 93 172 - (172) 93
Operating income 90 177 (24) - 243
Other income 20 1 9 (7) 23
Interest expense 68 - 15 (7) 76
Income before income
taxes 42 178 (30) - 190
Income taxes 20 71 (26) - 65
Net income 22 107 (4) - 125
Total assets 2,860 718 205 (141) 3,642
Expenditures for long-
lived assets 163 7 9 - 179
2000
Revenues from external
customers $ 650 $2,136 $ 23 $ - $2,809
Intersegment revenues 187 326 - (326) 187
Operating income 169 95 (16) - 248
Other income 17 3 15 (5) 30
Interest expense 64 - 8 (5) 67
Income before income
taxes 122 98 (9) - 211
Income taxes 48 38 (15) - 71
Net income 74 60 6 - 140
Total assets 2,530 1,312 198 - 4,040
Expenditures for long-
lived assets 126 7 38 - 171
1999
Revenues from external
customers $ 496 $ 746 $ 27 $ - $1,269
Intersegment revenues 164 126 - (126) 164
Operating income 172 22 (7) - 187
Other income 15 - 3 (1) 17
Interest expense 62 1 5 (1) 67
Income before income
taxes 125 21 (9) - 137
Income taxes 50 8 (12) - 46
Net income 75 13 3 - 91
Total assets 2,379 128 133 - 2,640
Expenditures for long-
lived assets 113 - 27 - 140
The intersegment revenues from Utility Operation to Energy Marketing are not
eliminated because they are included in the regulatory cost mechanism for IPC.
13. REGULATORY ASSETS AND LIABILITIES:
The following is a breakdown of IPC's regulatory assets and liabilities for
the years 2001 and 2000:
2001 2000
Assets Liabilities Assets Liabilities
(millions of dollars)
Income taxes $ 210 $ 41 $ 214 $ 40
Conservation 28 4 32 4
Employee benefits 3 - 4 -
PCA deferral and
amortization 290 - 120 -
Oregon deferral and
amortization 15 - - -
Derivatives 48 - - -
Other 6 1 9 1
Deferred investment tax
credits - 68 - 66
Total $ 600 $ 114 $ 379 $ 111
At December 31, 2001, IPC had $4 million of regulatory assets, primarily
SFAS 112 benefits and reorganization costs,that were not earning a
return on investment excluding the $210 million that relates to income
taxes and $48 million that relates to derivatives. The amortization
periods range from three to four years, respectively.
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.
Idaho Jurisdiction
PCA: In the 2001 PCA filing, IPC requested recovery of $227 million of
power supply costs. In May, the IPUC authorized recovery of $168 million,
but deferred recovery of $59 million pending further review. The
approved amount resulted in an average rate increase of 31.6 percent.
After conducting hearings on the remaining $59 million the IPUC
authorized recovery of $48 million plus $1 million of accrued interest,
beginning in October 2001. The remaining $11 million not recovered in
rates from the PCA filing was written off in September 2001.
Of the $227 million requested by IPC, $185 million related to the true-up
of power supply costs incurred in the 2000-2001 PCA year and $42 million
was for recovery of excess power supply costs forecasted in the 2001-2002
PCA year. The forecast amount, however, underestimated expected power
supply costs due to reservoir water levels being less than forecast,
necessitating the use of higher cost alternatives to hydro generation.
Also market prices for purchased power were higher than forecast earlier
in the PCA year.
As part of the May 2001 PCA, the IPUC required IPC to implement a three-
tiered rate structure for Idaho residential customers. The IPUC
determined that the approved rates for residential customers should
increase as the customer's electricity consumption increases. The
residential rate increases are 14.4 percent for the first 800 kWh of
usage, 28.8 percent for the next 1,200 kWh, and 62 percent for the usage
over 2,000 kWh.
On October 18, 2001 IPC filed an application with the IPUC for an order
approving the costs to be included in the 2002-2003 PCA for the
Irrigation Load Reduction Program and the Astaris Load Reduction
Agreement. These two programs were implemented in 2001 to reduce demand
and were approved by the IPUC and the Oregon Public Utility Commission
(OPUC). The costs incurred in 2001 for these two programs were $70
million for the Irrigation Load Reduction Program and $62 million
for the Astaris Load Reduction Agreement through December 2001.
On August 31, 2001 IPC filed a request with the IPUC to implement a rate
credit to qualifying residential and small farm customers. The credit
is the result of a settlement agreement between IPC and the Bonneville
Power Administration (BPA), which will pass on the benefits of the
Federal Columbia River Power System. IPC estimates the credit could be
as much as $3.60 per month for residential customers who use 1,200 kWh
per month and $300 per month for farm customers that use 100,000 kWh.
The IPUC, by Order No. 28868, approved the credit to be passed to the
qualified customers effective October 1, 2001.
In its May 2001 rate authorization the IPUC also directed IPC to
reinstate a comprehensive conservation program given the current
volatility of market prices and the opportunity to incorporate long-term
conservation. In response to that directive, IPC filed a report of
present energy efficiency activities, a list of conservation measures,
an examination of funding options and a detailed program structure that
could be implemented should the Commission determine that additional
conservation programs, including the funding of these programs, is in
the public interest. The Commission has delayed further deliberations
until the spring of 2002.
So far in the 2001-2002 rate year actual power supply costs included in
the PCA have beensignificantly greater than forecast due to purchased
power volumes and prices being greaterthan originally forecasted and the
implementation of the voluntary load reductionprograms with Astaris and
the irrigation customers. To account for these higher-than-forecasted
costs and the unamortized portion of the 2000-2001 PCA balances, IPC has
recorded regulatoryassets of $290 million as of December 31, 2001.
The May 2000 rate adjustment increasedIdaho general business customer
rates by 9.5 percent, and resulted from forecasted below-average
hydroelectric generating conditions. Overall, the PCA adjustment
increased general business revenue by approximately $38 million during
the 2000-2001 rate period,partially offsetting the forecasted increase
in power supply costs.
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 1999-2000 rate period and a true-up from the 1998-1999
rate period. Overall, the May 1999 rate adjustment decreased annual
general business revenue by approximately $40 million during the
1999-2000 rate period.
Regulatory Settlement: IPC had a settlement agreement with 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 the year-end common equity, IPC set aside 50 percent of the excess for
the benefit of the 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 $10
million in 1999 earnings and $3 million in unused 1998 reserve balances
available for the benefit of the Idaho customers.
In April 2000 the IPUC issued Order 28333, which ordered that $7 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
for the years 2000-2004, ordering IPC to set aside the remaining $6
million of revenue sharing dollars to fund that participation.
Demand Side Management (DSM): 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 an application with the OPUC to begin
recovering extraordinary 2001 power supply costs in its Oregon
jurisdiction. On June 18, 2001, the OPUC approved new rates that
would recover $1 million over the next year. Under the provisions
of the deferred accounting statute, annual rate recovery amounts
were limited to three percent of IPC's 2000 gross revenues in Oregon.
During the 2001 session, the Oregon Legislature amended the statute
giving the OPUC authority to increase the maximum annual rate of
recovery of deferred amounts to six percent for electric utilities.
IPC subsequently filed on October 5, 2001 to recover an additional
three percent extraordinary deferred power supply costs. As a result
of this filing, the OPUC issued Order No. 01-994 allowing IPC to
increase its rate of recovery to six percent effective November
28, 2001. The Oregon deferral balance is $15 million as of December
31, 2001, net of the June 18, 2001 and November 28, 2001 recovery.
IPC filed with the OPUC a request to implement the same BPA program
as in Idaho. The OPUC held a public meeting on October 22, 2001 and
subsequently approved the Company's request to implement the BPA
Residential and Small Farm Energy Credit for the benefits derived
during the period October 1, 2001 through September 30, 2006.
In 1998, IPC received authority from the OPUC to reduce the amortization
period for the regulatory assets associated with DSM programs from 24
years to 5 years. The OPUC also approved additional Oregon allocated
DSM expenditures for recovery through rates. The Oregon costs will be
recovered by extending an existing surcharge until the amounts are
collected.
14. DERIVATIVE FINANCIAL INSTRUMENTS:
Energy Trading Contracts
The commodity transactions entered into by IE are classified as energy
trading contracts, or derivatives. Under SFAS 133 and EITF 98-10, these
contracts are recorded on the balance sheet at fair market value. This
accounting treatment is also referred to as mark-to-market accounting.
Mark-to-market accounting treatment can create a disconnect between
recorded earnings and realized cash flow. Marking a contract to market
consists of reevaluating the market value of the entire term of the
contract at each reporting period and reflecting the resulting gain or
loss in earnings for the period. This change in value represents the
difference between the contract price and the current market value of
the contract. The change in market value of the contract could result
in large gains or losses recorded in earnings at each subsequent
reporting period unless there are offsetting changes in value of hedge
contracts. The gain or loss generated from the change in market value
of the energy trading contracts is a non-cash event. If these contracts
are held to maturity, the cash flow from the contracts, and their hedges,
are realized over the life of the contract.
When determining the fair value of our marketing and trading contracts,
we use actively quoted prices for contracts with similar terms as the
quoted price, including specific delivery points and maturities. To
determine fair value of contracts with terms that are not consistent with
actively quoted prices we use, when available, prices provided by other
external sources. When prices from external sources are not available,
we determine prices by using internal pricing models that incorporate
available current and historical pricing information. Finally, we adjust
the fair market value of our contracts for the impact of market depth
and liquidity, potential model error, and expected credit losses at the
counterparty level.
The following table details the gross margin for the energy marketing
operations (in millions of dollars):
2001 2000 1999
Gross Margin:
Realized or otherwise settled $ 150 $ 181 $ 28
Unrealized 93 (35) 4
Total $ 243 $ 146 $ 32
Risk Management: 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 can withstand potentially
dramatic market fluctuations. To manage the risks inherent in the energy
commodity industry while implementing the Company's business strategy,
Risk Management Committee (RMC), comprised of Company officers, oversees
the Company's risk management program as defined in the 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.
To manage the risks inherent in its portfolio, the Company has
established risk limits. Market and credit risk is measured and reported
daily to the members of the RMC. Other tools used to manage credit risk
are the holding of collateral in the form of cash or letters of credit
and the use of margining agreements with counterparties when credit risk
exceeds certain pre-determined thresholds. Because of the volatile
nature of energy market prices, margining agreements can require the
posting of large amounts of cash between counterparties to hold as
collateral against the value of the energy contracts. This practice
mitigates credit risk but increases the need for cash or other liquid
securities to ensure the ability to meet all margin requirements when
the markets are most volatile.
Derivative Assets and Liabilities
The Company adopted SFAS 133, as amended, effective January 1, 2001.
Contracts company-wide were evaluated based upon the SFAS 133 derivative
definitions and requirements. Most of the Company's contracts that meet
the derivative definition are the energy trading contracts that were
already recorded at fair value under EITF 98-10 as discussed above.
Most of the remaining energy contracts meet the definition of a normal
purchase or sale and therefore are not considered derivatives. However,
IPC has certain electricity contracts that are periodically net settled
with the counterparty (booked out). Booking out of electricity
contracts is a normal business transaction within the electric utility
industry; however the FASB and the Derivatives Implementation Group (DIG)
of the FASB initially interpreted that book outs did not qualify for
the normal purchase and sales exception. The Company has recorded the
fair market value of the booked out system electricity contracts within
the financial statements as "Derivative liabilities."
Such assets and liabilities are as follows:
January 1, 2001 December 31, 2001
(millions of dollars)
Assets $ 109 $ -
Liabilities (207) (48)
Net $ (98) $ (48)
The electricity contracts identified above are subject to IPC regulatory
processes. Accordingly, SFAS 71 allows the net amount of these
derivative assets and liabilities to be offset by regulatory assets or
liabilities. The IPUC granted approval of this use of SFAS 71 regulatory
assets or liabilities in its Order No. 28661 issued March 12, 2001.
In June 2001 the DIG issued Interpretation C-15, which was amended in
October 2001, that tentatively concludes that certain booked out
contracts now qualify for the normal purchase and sales exception.
IPC is evaluating the effect of this new conclusion on its treatment
of booked out contracts and expects that some contracts previously
classified as derivatives will be exempt when C-15 becomes effective
for IPC on January 1, 2002. The effect of this change will not have a
material effect on IPC's financial position, results of operations, or
cash flows.
As a result of the items discussed above, the Company's adoption of
SFAS 133, as amended, did not have a material effect on its financial
position, results of operations, or cash flows.
INDEPENDENT AUDITORS' REPORT
To The Board of Directors and Shareholders of IDACORP, Inc.
Boise, Idaho
We have audited the accompanying consolidated balance sheets of IDACORP,
Inc. and its subsidiaries as of December 31, 2001 and 2000, and the
related consolidated statements of income, comprehensive income,
shareholders' equity and cash flows for each of the three years
in the period ended December 31, 2001. 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
satement 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, 2001 and 2000, and the results of their
operations and their cash flows for each of the three years in the
period ended December 31, 2001 in conformity with accounting principles
generally accepted in the United States of America. Also, in our opinion,
such consolidated financial statement schedule, when considered in
relation to the basic consolidated financial statements taken as a
whole, presents fairly in all material respects the information set
forth therein.
DELOITTE & TOUCHE LLP
Boise, Idaho
January 31, 2002
SUPPLEMENTAL FINANCIAL INFORMATION, UNAUDITED
QUARTERLY FINANCIAL DATA:
The following unaudited information is presented for each quarter of
2001 and 2000 (in millions of dollars except for per share amounts).
In the opinion of the Company, all adjustments necessary for a fair
statement of such amounts for such periods have been included.
The results of 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.
Quarter Ended
March 31 June 30 September 30 December 31
2001
Revenues $1,133 $1,578 $2,115 $ 821
Income from operations 65 73 66 38
Income taxes 17 22 17 8
Net income 35 36 34 20
Earnings per share of
common stock 0.93 0.96 0.91 0.55
2000
Revenues $ 352 $ 552 $1,039 $1,053
Income from operations 62 61 79 46
Income taxes 24 16 22 9
Net income 42 32 41 24
Earnings per share of
common stock 1.12 0.86 1.11 0.63
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None
PART III
Part III has been omitted because the registrant will file a definitive
proxy statement pursuant to Regulation 14A, which involves the election
of Directors, with the Commission within 120 days after the close of the
fiscal year, portions of which are hereby incorporated by reference
(except for information with respect to executive officers which is set
forth in Part I hereof).
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a) Please refer to Item 8, "Financial Statements and Supplementary Data"
for a complete listing of all consolidated financial statements and
financial statement schedules.
(b) Reports on SEC Form 8-K. The following Report on Form 8-K was filed
for the three months ended December 31, 2001.
Items Reported Date of Report
Item 5 - Other Events December 4, 2001
(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) 33-56071 3(d) Articles of Share Exchange, as filed
with the Secretary of State of Idaho
on September 29, 1998.
*3(b) 333-64737 3.1 Articles of Incorporation of
IDACORP, Inc.
*3(b)(i) 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(b)(ii) 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(c) 1-14465 3(c) Amended Bylaws of IDACORP, Inc. as
Form 10-Q of July 8, 1999.
for 6/30/99
*4(a) 1-14465 4 Rights Agreement, dated as of
Form 8-K September 10, 1998, between IDACORP,
dated Inc. and Wells Fargo Bank as
September 15, successor to The Bank of New York,
1998 as Rights Agent.
*4(b) 1-14465 4.1 Indenture for Senior Debt Securities
Form 8-K dated as of February 1, 2001,
dated February between IDACORP, Inc. and Bankers
28, 2001 Trust Company, as Trustee.
*4(c) 1-14465 4.2 First Supplemental Indenture dated
Form 8-K as of February 1, 2001, to Indenture
dated February for Senior Debt Securities dated as
28, 2001 of February 1, 2001 between IDACORP,
Inc. and Bankers Trust Company, as
Trustee.
*10(a) 1-3198 10(n)(i) The Revised Security Plan for Senior
Form 10-K Management Employees - a non-
for 1994 qualified, deferred compensation
plan effective August 1, 1996.
*10(b) 1-3198 10(n)(ii) The Executive Annual Incentive Plan
Form 10-K for senior management employees of
for 1994 IPC effective January 1, 2001.
*10(c) 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(d) 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(e) 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(f) 1-3198 10(y) Executive Employment Agreement dated
Form 10-K November 20, 1996 between IPC and
for 1997 Richard R. Riazzi.
*10(g) 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) 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(i) 1-14465 10(h)(ix) IDACORP, Inc. 2000 Long-Term
Form 10-K Incentive and Compensation Plan.
for 1999
12 Statement Re: Computation of Ratio
of Earnings to Fixed Charges.
12(a) Statement Re: Computation of
Supplemental Ratio of Earnings to
Fixed Charges.
12(b) Statement Re: Computation of Ratio
of Earnings to Combined Fixed
Charges and Preferred Dividend
Requirements.
12(c) Statement Re: Computation of
Supplemental Ratio of Earnings to
Combined Fixed Charges and Preferred
Dividend Requirements.
21 Subsidiaries of IDACORP, Inc.
23 Independent Auditors' Consent.
IDACORP, Inc.
SCHEDULE II - CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
Years Ended December 31, 2001, 2000 and 1999
Column A Column B Column C Column D Column E
Additions
Charged
Balance At Charged (Credited) Balance
Beginning to to Other Deductions At End Of
Classification Of Period Income Accounts (1) Period
(Millions of dollars)
2001:
Reserves Deducted From
Applicable Assets:
Reserve for
uncollectible
accounts $ 23 $ 28 $ - $ 8 $ 43
Other Reserves:
Rate refunds $ - $ - $ - $ - $ -
Injuries and damages
reserve $ 2 $ - $ - $ - $ 2
Miscellaneous
operating reserves $ 5 $ - $ - $ 1 $ 4
2000:
Reserves Deducted From
Applicable Assets:
Reserve for
uncollectible
accounts $ 1 $ 23 $ - $ 1 $ 23
Other Reserves:
Rate refunds $ 9 $ 3 $ - $ 12 $ -
Injuries and damages
reserve $ 2 $ - $ - $ - $ 2
Miscellaneous
operating reserves $ 9 $ - $ - $ 4 $ 5
1999:
Reserves Deducted From
Applicable Assets:
Reserve for
uncollectible
accounts $ 1 $ 2 $ - $ 2 $ 1
Other Reserves:
Rate refunds $ 5 $ 11 $ - $ 7 $ 9
Injuries and damages
reserve $ 2 $ - $ - $ - $ 2
Miscellaneous
operating reserves $ 7 $ 3 $ - $ 2 $ 8
Notes: (1) Represents deductions from the reserves for purposes for
which the reserves were created.
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 22, 2002 By: /s/Jan B.Packwood
Jan B. Packwood
President and Chief Executive
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 22, 2002
Jon H. Miller
By:/s/ Jan B. Packwood President and Chief "
Jan B. Packwood Executive Officer
and Director
By:/s/ Darrel T. Anderson Vice President, Chief "
Darrel T. Anderson Financial Officer and
Treasurer
(Principal Financial Officer)
(Principal Accounting Officer)
By:/s/ Rotchford L. Barker By:/s/ Evelyn Loveless "
Rotchford L. Barker Evelyn Loveless
Director Director
By:/s/ Roger L. Breezley By:/s/ Gary G. Michael "
Roger L. Breezley Gary G. Michael
Director Director
By:/s/ John B. Carley By:/s/ Peter S. O'Neill "
John B. Carley Peter S. O'Neill
Director Director
By: By:/s/ Robert A. Tinstman "
Christopher L. Culp Robert A. Tinstman
Director Director
By:/s/ Jack K. Lemley "
Jack K. Lemley
Director
EXHIBIT INDEX
Exhibit Page
Number Number
10(n)(ii) The Executive Annual Incentive
Plan for senior management
employees of IPC effective
January 1, 2001.
12 Statements Re: Computation of
Ratio of Earnings to Fixed
Charges.
12(a) Statements Re: Computation of
Supplemental Ratio of
Earnings to Fixed Charges
12(b) Statements Re: Computation of
Ratio of Earnings to Combined
Fixed Charges and Preferred
Dividend Requirements.
12(c) Statements Re: Computation of
Supplemental Ratio of
Earnings to Combined Fixed
Charges and Preferred
Dividend Requirements.
21 Subsidiaries of IDACORP, Inc.
23 Independent Auditors' Consent.