Back to GetFilings.com
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
X ANNUAL REPORT PURSUANT TO SECTION 13 OR 15 (D) OF THE SECURITY
EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2000
OR
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15 (D) OF THE SECURITY
EXCHANGE ACT OF 1934
For the transition period from .............. to...............
Exact name of Registrants
as specified in their charters,
address of principal executive
Commission offices and Registrants' IRS Employer Iden-
File Number telephone number tification Number
1-14465 IDACORP, Inc. 82-0505802
1-3198 Idaho Power Company 82-0130980
1221 W. Idaho Street
Boise, ID 83702-5627
(208) 388-2200
State or other jurisdiction of incorporation: Idaho
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT: Name of
exchange on
which registered
IDACORP, Inc.: Common Stock, without par value New York and Pacific
Preferred Stock Purchase Rights
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:
Idaho Power Company: Preferred Stock
Indicate by check mark whether the registrants (1) have filed all
reports required to be filed by Section 13 or 15(d) of the
Securities Exchange Act of 1934 during the preceding 12 months (or
for such shorter period that the registrants were required to file
such reports), and (2) have been subject to such filing
requirements for the past 90 days.
Yes ( X ) No ( )
Indicate by check mark if disclosure of delinquent filers pursuant
to Item 405 of Regulation S-K is not contained herein, and will not
be contained, to the best of registrants' knowledge, in definitive
proxy or information statements incorporated by reference in Part
III of this Form 10-K or any amendment to this Form 10-K. ( )
Aggregate market value of voting and non-voting common stock held
by nonaffiliates (March 1, 2001)
IDACORP, Inc.: $1,399,591,939
Idaho Power Company: None
Number of shares of common stock outstanding at March 1, 2001:
IDACORP, Inc.: 37,415,746
Idaho Power Company: 37,612,351 shares, all of which are
held by IDACORP, Inc.
Documents Incorporated by Reference:
Part III, Item 10 - 13 Portions of the joint definitive proxy
statement of the Registrant.
to be filed pursuant to Regulation 14A
for the 2001 Annual Meeting of Shareholders
to be held on May 17, 2001.
This Combined Form 10-K represents separate filings by IDACORP,
Inc. and Idaho Power Company. Information contained herein
relating to an individual registrant is filed by that registrant on
its own behalf. Idaho Power Company makes no representations as to
the information relating to IDACORP, Inc.'s other operations.
TABLE OF CONTENTS
PART I
PAGE
ITEM 1. BUSINESS 1
OVERVIEW 1
UTILITY OPERATIONS 1
ELECTRIC INDUSTRY RESTRUCTURING 2
REGULATION 3
RATES 3
POWER SUPPLY 5
FUEL 6
WATER RIGHTS 7
ENVIRONMENTAL REGULATION 7
DIVERSIFIED BUSINESS OPERATIONS 9
ENERGY MARKETING 9
OTHER 10
RESEARCH AND DEVELOPMENT 11
CONSTRUCTION PROGRAM 11
FINANCING PROGRAM 12
ITEM 2. PROPERTIES 13
ITEM 3. LEGAL PROCEEDINGS 15
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS 15
EXECUTIVE OFFICERS OF THE REGISTRANTS 16
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON STOCK AND RELATED
STOCKHOLDER MATTERS 19
ITEM 6. SELECTED FINANCIAL DATA 20
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS 21
ITEM 7A.QUALITATIVE AND QUANTITATIVE DISCLOSURE ABOUT MARKET
RISK 35
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA 37
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE 75
PART III
ITEM 10.DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANTS* 75
ITEM 11.EXECUTIVE COMPENSATION* 75
ITEM 12.SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT* 75
ITEM 13.CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS* 75
PART IV
ITEM 14.EXHIBITS, FINANCIAL STATEMENT SCHEDULE AND REPORTS ON
FORM 8-K 75
SIGNATURES 81
*INCORPORATED BY REFERENCE.
PART I - IDACORP, Inc. and Idaho Power Company
ITEM 1. BUSINESS
SAFE HARBOR STATEMENT
This Form 10-K contains "forward-looking statements" intended to
qualify for safe harbor from liability established by the Private
Securities Litigation Reform Act of 1995. Forward-looking
statements should be read with the cautionary statements and
important factors included in this Form 10-K at Part II, Item 7-
"Management's Discussion and Analysis of Financial Condition and
Results of Operations - Forward-Looking Information". Forward-
looking statements are all statements other than statements of
historical fact, including without limitation those that are
identified by the use of the words "anticipates," "estimates,"
"expects," "intends," "plans," "predicts," and similar
expressions.
OVERVIEW
IDACORP, Inc. (IDACORP or the Company) is a holding company
incorporated in 1998 under the laws of the state of Idaho. On
October 1, 1998, IDACORP became the parent of Idaho Power Company
(IPC). IPC is a regulated electric utility, and also conducts
IDACORP's unregulated electricity marketing operations.
IDACORP's other significant operating subsidiaries are:
IDACORP Energy - natural gas marketing
Ida-West Energy - independent power projects development and
management
IdaTech - developer of integrated fuel cell systems
IDACORP Financial Services (IFS) - affordable housing and other
real estate investments
Rocky Mountain Communications - commercial and residential
Internet service provider
IDACOMM - provider of telecommunications services
IDACORP Services - energy related products and services
Applied Power Company (APC) - supplier of photovoltaic systems
(sold January 2001).
Ownership of Ida-West was transferred by IPC to IDACORP upon
formation of the holding company in 1998. APC and IFS were
transferred by IPC to IDACORP effective January 1, 2000. At
December 31, 2000, IDACORP had 2,044 full-time employees.
IDACORP has identified two reportable business segments, the
regulated utility operations of IPC, and the energy marketing
activities of IPC and IDACORP Energy. We present information
about our operating segments in Note 12 to the Consolidated
Financial Statements. These segments and our other operations are
described below.
UTILITY OPERATIONS
IPC was incorporated under the laws of the state of Idaho in 1989
as successor to a Maine corporation organized in 1915. IPC in
involved in the generation, purchase, transmission, distribution
and sale of electric energy in a 20,000 square mile area in
southern Idaho, eastern Idaho and northern Nevada, with an
estimated population of 814,000. IPC holds franchises in 72
cities in Idaho and ten cities in Oregon and holds certificates
from the respective public utility regulatory authorities to serve
all or a portion of 28 counties in Idaho, three counties in
Oregon, and one county in Nevada. As of December 31, 2000, IPC
supplied electric energy to over 390,000 general business
customers and had 1,713 full-time employees.
IPC owns and operates 17 hydroelectric power plants and shares
ownership in three coal-fired generating plants. These generating
plants and their capacities are listed in Item 2. "Properties."
IPC's coal-fired plants are in Wyoming, Oregon and Nevada, and use
low-sulfur coal from Wyoming and Utah.
IPC relies heavily on hydroelectric power for its generating needs
and is one of the nation's few investor-owned utilities with a
predominantly hydroelectric generating base. Because of its
reliance on hydro generation, IPC's generation operations can be
significantly affected by the weather. The availability of
inexpensive hydroelectric power depends on snowpack in the
mountains above IPC's hydro facilities, precipitation and other
weather and streamflow management considerations. When
hydroelectric generation decreases and customer demand increases,
IPC increases its use of more expensive thermal generation and
purchased power.
The rates we charge to our general business customers are
determined by the various regulatory authorities. Approximately
95 percent of our general business revenue and sales come from
customers in the State of Idaho. The rates we charge these
customers, (except for customers with special contracts) are
adjusted annually by a power cost adjustment (PCA) mechanism. The
PCA adjusts rates to reflect the changes in costs incurred by IPC
to supply power. Throughout the year, we compare our actual power
supply costs to the amounts we are recovering in rates. Most, but
not all, of this difference is deferred and included in the
calculation of rates for future years. The effect of the PCA is
to lessen the impact that water conditions have on earnings. The
PCA is discussed in more detail below in "Rates."
The primary influences on electricity sales are weather and
economic conditions. Generally, extreme temperatures increase
sales to customers, who use electricity for cooling and heating,
and moderate temperatures decrease sales. Precipitation levels
during the growing season affect sales to customers who use
electricity to operate irrigation pumps. Increased precipitation
reduces electricity usage by these customers.
With its predominantly hydroelectric base and low-cost coal-fired
plants, IPC has historically been one of the lowest-cost producers
of electric energy among the nation's investor-owned utilities.
Through its interconnections with the Bonneville Power
Administration (BPA) and other utilities, IPC has access to all
the major electric systems in the West.
For the year ended December 31, 2000, total revenues from
residential customers accounted for 40 percent of total general
business revenues. Commercial customers with less than 1,000
kilowatt (kW) demand accounted for 23 percent, industrial
customers with 1,000 kW demand or more accounted for 24 percent,
and irrigation customers accounted for 13 percent.
IPC's principal commercial and industrial customers are involved
in: elemental phosphorus production, food processing, phosphate
fertilizer production, electronics and general manufacturing,
lumber, beet sugar refining, and the skiing industry.
ELECTRIC INDUSTRY RESTRUCTURING
The legislatures and/or regulatory commissions in several states,
and at a national level, have considered or are considering
various forms of retail competition. In 1997, the Idaho
Legislature appointed a committee to study restructuring of the
electric utility industry. Although the committee will continue
studying a variety of restructuring ideas, it has not recommended
any restructuring legislation and is not expected to in the
foreseeable future. In 1999, the Oregon legislature passed
legislation restructuring the electric utility industry, but
exempted IPC's service territory.
In December 1999, the FERC issued Order No. 2000, dealing with
Regional Transmission Organizations (RTOs), which are discussed
further below in "Power Supply - Transmission Services."
REGULATION
IPC is under the regulatory jurisdiction (as to rates, service,
accounting and other general matters of utility operation) of the
Federal Energy Regulatory Commission (FERC), the Idaho Public
Utilities Commission (IPUC), the Oregon Public Utility Commission
(OPUC) and the Public Utility Commission of Nevada (PUCN). IPC is
also under the regulatory jurisdiction of the IPUC, OPUC and the
Public Service Commission of Wyoming as to the issuance of
securities. IPC is subject to the provisions of the Federal Power
Act as a "licensee" and "public utility" as therein defined.
IPC's retail rates are established under the jurisdiction of the
state regulatory agencies and its wholesale and transmission rates
are regulated by the FERC (See "Rates"). Pursuant to the
requirements of Section 210 of the Public Utilities Regulatory
Policy Act of 1978 (PURPA), the state regulatory agencies have
each issued orders and rules regulating IPC's purchase of power
from Cogeneration and Small Power Production (CSPP) facilities.
As a licensee under the Federal Power Act, IPC and its licensed
hydroelectric projects are subject to the provisions of Part I of
the Act. All licenses are subject to conditions set forth in the
Act and related FERC regulations. These conditions and
regulations include provisions relating to condemnation of a
project upon payment of just compensation, amortization of project
investment from excess project earnings, possible takeover of a
project after expiration of its license upon payment of net
investment, severance damages, and other matters.
The state of Oregon has a Hydroelectric Act providing for
licensing of hydroelectric projects in that state. IPC's
Brownlee, Oxbow and Hells Canyon facilities are on the Snake River
where it forms the boundary between Idaho and Oregon and occupy
land located in both states. With respect to project property
located in Oregon, these facilities are subject to the Oregon
Hydroelectric Act. IPC has obtained Oregon licenses for these
facilities and these licenses are not in conflict with the Federal
Power Act or IPC's FERC license (see Item 2. "Properties").
RATES
Idaho Jurisdiction -
IPC has a PCA mechanism that provides for annual adjustments to
the rates charged to its Idaho retail electric customers. These
adjustments, which take effect annually on May 16, are based on
forecasts of net power supply costs, and the true-up of the prior
year's forecast. The difference between the actual costs incurred
and the forecasted costs is deferred, with interest, and trued-up
in the next annual rate adjustment.
The IPUC approved IPC's May 16, 2000 PCA adjustment, issuing Order
28358 dated May 9, 2000. This rate adjustment increased Idaho
general business customer rates by 9.5 percent, and resulted from
forecasted below-average hydroelectric generating conditions.
Overall, the PCA adjustment is expected to increase general
business revenue by $38 million during the 2000-2001 rate period,
partially offsetting the forecasted increase in power supply
costs.
So far in the 2000-2001 PCA rate year, actual power supply costs
have been significantly greater than the forecast, due to actual
hydroelectric generation being below the forecast, and purchased
power volumes and prices being substantially above the forecast.
To account for these higher-than-forecasted costs, IPC has
recorded a regulatory asset of $161 million as of January 31,
2001.
In February 2001, IPC filed an application with the IPUC
proposing to implement a one-year emergency fuel charge due to
these extraordinarily high expenses. The IPUC suspended the
proposed effective date of March 26, 2001 to May 1, 2001, to
allow for public workshops and hearings to be held on the matter.
The IPUC also ordered IPC to make its annual PCA filing as soon
as possible so that the cases can be filed jointly.
The May 1999 rate adjustment reduced rates by 9.2 percent. The
decrease was the result of both forecasted above-average
hydroelectric generating conditions for the upcoming year and a
true-up from the 1998-99 rate period. Overall, the May 1999 rate
adjustment decreased annual general business revenue by
approximately $40 million during the 1999-2000 rate period.
The May 1998 rate adjustment increased annual revenue by $34
million over the amount that would have been recorded at the 1997-
98 rates. The 1998-99 forecast had assumed a return to more
normal hydroelectric generating conditions from the above-average
conditions experienced in the prior year. This resulted in
forecasted power supply costs being near the amounts used in base
rates.
IPC had a settlement agreement with the IPUC that expired at the
end of 1999. Under the terms of the settlement, when earnings in
IPC's Idaho jurisdiction exceeded an 11.75 percent return on year-
end common equity, IPC set aside 50 percent of the excess for the
benefit of Idaho retail customers.
In March 2000 IPC submitted its 1999 annual earnings sharing
compliance filing to the IPUC. This filing indicated that there
was almost $9.6 million in 1999 earnings and $2.7 million in
unused 1998 reserve balances available for the benefit of our
Idaho customers.
In April 2000 the IPUC issued Order 28333, which ordered that $6.9
million of the revenue sharing balance be refunded to Idaho
customers through rate reductions effective May 16, 2000. The
Order also approved IPC's continued participation in the Northwest
Energy Efficiency Alliance (NEEA) for the years 2000-2004,
ordering IPC to set aside the remaining $5.4 million of revenue
sharing dollars to fund that participation.
IPC requested that the IPUC allow for the recovery of post-1993
DSM expenses and acceleration of the recovery of DSM expenditures
authorized in the last general rate case. In its Order No. 27660
issued on July 31, 1998, the IPUC set a new amortization period of
12 years instead of the 24-year period previously adopted. On
April 17, 2000, the Idaho Supreme Court affirmed the IPUC order,
after hearing an appeal by a group of industrial customers.
On February 23, 2001, the IPUC approved IPC's Green Energy
Purchase Program. The Green Program is an optional program
available to all IPC customers in Idaho, allowing them to pay a
premium to purchase energy generated by alternative sources such
as solar and wind. Creating the Green Program will provide
additional means for customers to stimulate demand for new green
resources and their development.
Other Jurisdictions -
IPC filed with the OPUC on December 19, 2000 for an accounting
order to defer for later ratemaking treatment excess net power
supply costs expected to be incurred in 2001.
In 1998, IPC received authority from the OPUC to reduce the
amortization period for the regulatory assets associated with
demand-side management programs from 24 years to five years. The
OPUC also approved additional Oregon allocated demand-side
management expenditures for recovery through rates. The Oregon
costs will be recovered by extending an existing surcharge until
the amounts are collected.
The IPUC has approved IPC's sale of its Nevada service territory
to Raft River Electric Co-Op. This sale transfers the
transmission facilities and rights-of-way that serve about 1,250
customers in northern Nevada and about 90 customers in southern
Idaho. The sale must still be approved by the PUCN. The FERC has
approved a power supply agreement between IPC and Raft River.
This sale will allow IDACORP to participate in a deregulated
electric utility market in the State of Nevada.
POWER SUPPLY
IPC meets its system load requirements using a combination of its
own system generation, mandated purchases from private developers
(see "CSPP Purchases" below) and purchases from other utilities
and power producers. IPC's generating stations and capacities are
listed in "Item 2. Properties". Historically, under normal water
conditions, IPC's hydro system supplies approximately 56 percent,
thermal generation accounts for 33 percent and purchased power and
other interchanges contribute the remaining 11 percent of total
system resources. IPC's system is dual-peaking, with the larger
peak demand generally occurring in the summer. The system peak
demand for 2000 was 2,919 MW, set on July 12, 2000. Peak demands
in 1999 and 1998 were 2,839 MW and 2,747 MW respectively. IPC
expects total system energy requirements to grow 1.8 percent
annually over the next five years.
Every two years, IPC is required to file with the IPUC and OPUC an
Integrated Resource Plan (IRP), a comprehensive look at IPC's
present and future demands for electricity and plan for meeting
that demand. The 2000 IRP identifies a potential electricity
shortfall within IPC's utility service territory by mid-2004. The
IRP projects a 250-MW resource need in 2004 to satisfy energy
demand during IPC's peak periods. Prior to 2004, the IRP calls
for IPC to increase purchases from the Northwest energy markets to
meet short-term energy needs. IPC anticipates that after 2004,
transmission constraints will not allow it to continue to cover
increasing demand by increasing purchases.
IPC issued a request for proposals seeking bids for 250 MW of
additional generation to support the growing demand in its utility
service territory. A proposal by Garnet Energy LLC, a subsidiary
of Ida-West Energy, was selected by IPC. Garnet has proposed
constructing and owning a natural gas-fired turbine facility
near Middleton, Idaho. In January 2001 IPC signed an agreement
with Garnet to define the conditions under which the utility will
purchase energy produced at the 250-MW project.
In March 2001, IPC announced plans to build a 90-MW combustion
turbine power plant near Mountain Home, Idaho. The project is
expected to be completed in July 2001, though it must still
complete environmental and other permitting processes before
construction can begin.
Because of its reliance upon hydroelectric generation, which
varies according to streamflows, IPC's generating system can be
constrained by resource (water) availability. In 1998 and 1999,
IPC's hydro generating system experienced above average water
years, but 2000 has brought below normal water conditions.
Current mountain snowpack above Brownlee Reservoir, the main
storage pool for the Hells Canyon hydro facilities, was at 55
percent of normal in February 2001.
Seasonal exchanges of winter-for-summer power are included among
the contracted resources to maximize the firm load carrying
capability. Exchanges are currently made with The Montana Power
Company under a contract that expires no earlier than 2003 and
with Seattle City Light under a contract that expires in 2003.
IPC's generating facilities are interconnected through its
integrated transmission system and are operated on a coordinated
basis to achieve maximum load-carrying capability and reliability.
IPC's transmission system is directly interconnected with the
transmission systems of the Bonneville Power Administration Avista
Corporation, PacifiCorp, The Montana Power Company and Sierra
Pacific Power Company. Such interconnections, coupled with
transmission line capacity made available under agreements with
certain of the above utilities, permit the interchange, purchase
and sale of power among all major electric systems in the West.
IPC is a member of the Western Systems Coordinating Council, the
Western Systems Power Pool, the Northwest Power Pool, the Western
Regional Transmission Association and the Northwest Regional
Transmission Association (see RTO discussion below in
"Transmission Services").
CSPP Purchases -
As a result of the enactment of the PURPA and the adoption of
avoided cost standards by the IPUC, IPC has entered into contracts
for the purchase of energy from private developers. Because IPC's
service territory encompasses substantial irrigation canal
development, forest product production facilities, mountain
streams, and food processing facilities, considerable amounts of
energy are available from these sources. Such energy comes from
hydropower producers who own and operate small plants and from
cogenerators converting waste heat or steam from industrial
processes into electricity. The total cost of power purchased
from CSPP projects was $53.7 million in 2000. During 2000, IPC
purchased 862.3 million kWh of power from these private developers
at a blended price of 6.2 cents per kWh.
The IPUC has determined that negotiated rates for future CSPP
projects larger than one MW should be tied more closely to values
determined in IPC's integrated resource planning process and has
limited the length of new contracts to a maximum of five years.
Wholesale Power Sales -
IPC has firm wholesale power sales contracts with several
entities. These contracts are for various amounts of energy, up
to 100 average megawatts, and are of various lengths expiring
between 2001and 2009.
Transmission Services -
IPC has long had an informal open-access transmission policy and
is experienced in providing reliable, high quality, economical
transmission service. IPC provides various firm and non-firm
wheeling services for several surrounding utilities.
In December 1999 the FERC, in its landmark Order 2000, said that
all companies with transmission assets must file to form RTOs or
explain why they cannot. Order 2000 is a follow up to orders 888
and 889 issued in 1996, which required transmission owners to
provide non-discriminatory transmission service to third parties.
By encouraging the formation of RTOs, the FERC seeks to further
facilitate the formation of liquid wholesale electricity markets.
In response to FERC Order 2000, IPC and other regional
transmission owners filed in October 2000 a plan to form RTO West,
an independent entity that will operate the transmission grid in
eight western states. RTO West will have its own independent
governing board. The participating transmission owners will retain
ownership of the lines, but will not have a role in operating the
grid.
The FERC filing represents a major portion of the filing necessary
to form RTO West. However, substantial additional filings will be
necessary to include the tariff and integration agreements
associated with the new entity and filings for state approvals. We
expect the FERC filings to be completed by the summer of 2001 and
state filings to be initiated in late 2001 or early 2002.
IPC's system lies between and is interconnected to the winter-
peaking northern and summer-peaking southern regions of the
western interconnected power system. This position allows IPC to
both provide transmission services and reach a broad power sales
market. IPC is a member of both the Western Regional Transmission
Association and the Northwest Regional Transmission Association.
These associations help facilitate transmission access and
planning throughout the power system.
FUEL
IPC, through its subsidiary Idaho Energy Resources Co., owns a one-
third interest in the Bridger Coal Company, which owns the Jim
Bridger mine supplying coal to the Jim Bridger generating plant in
Wyoming. The mine, located near the Jim Bridger plant, operates
under a long-term sales agreement that provides for delivery of
coal over a 51-year period ending in 2025. The Jim Bridger mine
has sufficient reserves to provide coal deliveries pursuant to the
sales agreement. IPC also has a coal supply contract providing
for annual deliveries of coal through 2005 from the Black Butte
Coal Company's Black Butte and Leucite Hills mines located near
the Jim Bridger project. This contract supplements the Bridger
Coal Company deliveries and provides another coal supply to
operate the Jim Bridger plant. The Jim Bridger plant's rail load-
in facility and unit coal train allows the plant to take advantage
of potentially lower-cost coal from outside mines for tonnage
requirements above established contract minimums.
Sierra Pacific Power Company (SPPCo), with whom IPC is a joint
(50/50) participant in the ownership and operation of the North
Valmy Steam Electric Generating plant (Valmy), has a long-term
coal contract with Southern Utah Fuel Company, a subsidiary of
Canyon Fuel Co., LLC. This contract, which expires on June 30,
2003, calls for the delivery of up to 17.5 million tons of low-
sulfur coal from a mine near Salina, Utah, for Valmy Unit No. 1.
In 1986 IPC and SPPCo signed a long-term coal supply agreement
with the Black Butte Coal Company. This contract provides for
Black Butte to supply coal to the Valmy project under a flexible
delivery schedule that allows for variations in the number of tons
to be delivered ranging from a minimum of 300,000 tons per year to
a maximum of 1 million tons per year. This flexibility
accommodates fluctuations in energy demand, hydroelectric
generating conditions and purchases of energy from CSPP
facilities.
WATER RIGHTS
Except as discussed below, IPC has acquired valid water rights
under applicable state law for all waters used in its
hydroelectric generating facilities. In addition, IPC holds water
rights for domestic, irrigation, commercial and other necessary
purposes related to other land and facility holdings within the
state. The exercise and use of all of these water rights are
subject to prior rights and, with respect to certain hydroelectric
facilities, IPC's water rights for power generation are
subordinated to future upstream diversions of water for irrigation
and other recognized consumptive uses.
Over time, increased irrigation development and other consumptive
diversions have resulted in some reduction in the stream flows
available to fulfill IPC's water rights at certain hydroelectric
generating facilities. In reaction to these reductions, IPC
initiated and continues to pursue a course of action to determine
and protect its water rights. As part of this process, IPC and
the state of Idaho signed the Swan Falls agreement on October 25,
1984 which provided a level of protection for IPC's hydropower
water rights at specified plants by setting minimum stream flows
and establishing an administrative process governing the future
development of water rights that may affect IPC's hydroelectric
generation. In 1987, Congress passed and the President signed
into law House Bill 519. This legislation permitted
implementation of the Swan Falls agreement and further provided
that during the remaining term of certain of IPC's project
licenses that the relationship established by the agreement would
not be considered by the FERC as being inconsistent with the terms
of IPC's project licenses or imprudent for the purposes of
determining rates under Section 205 of the Federal Power Act. The
FERC entered an order implementing the legislation on March 25,
1988.
In addition to providing for the protection of IPC's hydropower
water rights, the Swan Falls agreement contemplated the initiation
of a general adjudication of all water uses within the Snake River
basin. In 1987, the director of the Idaho Department of Water
Resources filed a petition in state district court asking that the
court adjudicate all claims to water rights, whether based on
state or federal law, within the Snake River basin. A
commencement order initiating the Snake River Basin Adjudication
was signed by the court on November 19, 1987. This legal
proceeding was authorized by state statute based upon a
determination by the Idaho Legislature that the effective
management of the waters of the Snake River basin required a
comprehensive determination of the nature, extent and priority of
all water uses within the basin. The adjudication is expected to
continue for at least the next 10 years. IPC has filed claims to
its water rights within the basin and is actively participating in
the adjudication to ensure that its water rights and the operation
of its hydroelectric facilities are not adversely impacted. IPC
does not anticipate any modification of its water rights as a
result of the adjudication process.
ENVIRONMENTAL REGULATION
Environmental regulation at the federal, state, regional and local
levels is having a continuing impact on IPC's operations due to
the cost of installation and operation of equipment required for
compliance with such regulations and the modification of system
operations to accommodate such regulation.
Based upon present environmental laws and regulations, IPC
estimates its capital expenditures (excluding allowance for funds
used during construction) for environmental matters for 2001 and
during the period 2002-2005 will total approximately $11.1 million
and $49.6 million, respectively. Studies related to mitigation of
environmental concerns due to relicensing of hydro facilities will
be a major portion of these expenditures. IPC anticipates
incurring approximately $27.5 million annually of operating
expenses for environmental facilities during the period 2001-2005,
based upon present environmental laws and regulation.
Clean Air -
IPC has analyzed the Clean Air Act legislation and its effects
upon IPC and its ratepayers. IPC's coal-fired plants in Nevada
and Oregon already meet the federal emission rate standards for
sulfur dioxide (SO2) and IPC's coal-fired plant in Wyoming meets
that state's even more stringent SO2 regulations. The Company
foresees no material adverse effects upon its operations with
regard to SO2 emissions.
In July 1997 the Environmental Protection Agency (EPA) announced
new National Ambient Air Quality Standards (NAAQS) for ozone and
Particulate Matter (PM) and in July 1999 the EPA announced
regional haze regulations for protection of visibility in national
parks and wilderness areas. On May 14, 1999, a federal court
ruling blocked implementation of these standards, which EPA
proposed in 1997. In November 2000, the EPA appealed to the U.S.
Supreme Court to reconsider that decision. A ruling should be
made on that appeal in mid-2001. Impacts of the ozone and PM
regulations and regional haze regulations on IPC's thermal
operations are unknown at this time.
North Valmy, Boardman and Jim Bridger Unit 4 elected to meet Phase
I nitrogen oxide (NOx ) limits beginning in 1998. As a result of
this voluntary "early election" these units will not be required
to meet the more restrictive Phase II NO x limits until 2008. Had
the units not voluntarily "early elected," they would have been
required to meet the Phase II limits in 2000. Jim Bridger Units
1, 2, and 3 were accepted as substitution units in 1995 and are
subject to NO x limits of Phase I instead of the more restrictive
limits of Phase II. Jim Bridger has installed low NO x equipment
to reduce NO x levels even lower than currently required.
Water -
IPC has received National Pollutant Discharge Elimination System
Permits, as required under the Federal Water Pollution Control Act
Amendments of 1972, for the discharge of effluents from its
hydroelectric generating plants.
IPC has agreed to meet certain dissolved oxygen standards at its
American Falls hydroelectric generating plant. IPC signed
amendments to the agreements relating to the operation of the
American Falls Dam and the location of water quality monitoring
facilities. The amendments were made to provide more accurate and
reliable water quality measurements necessary to maintain water
quality standards downstream from IPC's plant during the period
from May 15 to October 15 each year.
IPC has installed aeration equipment, water quality monitors and
data processing equipment as part of the Cascade hydroelectric
project to provide accurate water quality data and increase
dissolved oxygen levels as necessary to maintain water quality
standards on the Payette River. IPC has also installed and
operates water quality monitors at the Milner, Shoshone Falls,
Twin Falls, Upper Salmon, Lower Salmon and Bliss hydroelectric
projects, in order to meet compliance standards for water quality.
IPC owns and finances the operation of anadromous fish hatcheries
and related facilities to mitigate the effects of its
hydroelectric dams on fish populations. In connection with its
fish facilities, IPC sponsors ongoing programs for the control of
fish disease and improvement of fish production. IPC's anadromous
fish facilities at Hells Canyon, Oxbow, Rapid River, Pahsimeroi
and Niagara Springs continue to be operated under agreements with
the Idaho Department of Fish and Game. At December 31, 2000, the
investment in these facilities was $12.6 million and the annual
cost of operation pursuant to FERC License 1971 was approximately
$2.6 million annually.
Endangered Species -
Several species of salmon and Snake River mollusks living within
IPC's operating area are listed as threatened or endangered. IPC
continues to review and analyze the effect such designation has on
its operations. IPC is cooperating with various governmental
agencies to resolve issues related to these species. (See Part
II, Item 7. "Management's Discussion and Analysis of Financial
Condition and Results of Operations - Environmental Issues".)
Hazardous/Toxic Wastes and Substances -
Under the Toxic Substances Control Act (TSCA), the EPA has adopted
regulations governing the use, storage, inspection and disposal of
electrical equipment that contain polychlorinated biphenyls
(PCBs). The regulations permit the continued use and servicing of
certain electrical equipment (including transformers and
capacitors) that contain PCBs. IPC continues to meet all federal
requirements of TSCA for the continued use of equipment containing
PCBs. IPC has a program to make the 200-plus substations on its
system non-PCB. While IPC's use of equipment containing PCBs
falls well within the federal standards, IPC has voluntarily
decided to virtually eliminate these compounds from its system.
This program will save costs associated with the long-term
monitoring and testing of equipment and grounds for PCB
contamination as well as being good for the environment.. Total
IPC costs for the identification and disposal of PCBs from IPC's
system were $0.8 million, $0.6 million and $0.5 million for 2000,
1999 and 1998 respectively. IPC believes that all generation
facilities are presently non-PCB.
DIVERSIFIED BUSINESS OPERATIONS
IDACORP has been pursuing a strategy of expanding non-regulated
activities and separating the regulated utility operations of IPC
from non-regulated activities. The following discussion
highlights significant developments related to this strategy.
ENERGY MARKETING
To compete as an energy provider of choice, we have built a
trading operation that participates in the electricity, natural
gas and other related markets from our offices in Boise, Idaho and
Houston, Texas. Our energy marketing and trading strategy has
produced increasingly positive results over the last four years.
Our natural gas marketing capability continues to expand as the
electricity and natural gas markets move toward convergence, and
our electricity marketing efforts have resulted in volume and
income increases each year since inception of the strategy.
When buying and selling energy, the high volatility of energy
prices can have significant negative impact on profitability if
not appropriately managed. Also, counterparty creditworthiness is
key to ensuring that transactions entered into withstand dramatic
market fluctuations. To manage the risks inherent in the energy
commodity industry while implementing our business strategy, our
Risk Management Committee, comprised of Company officers, oversees
the risk management program as defined in our risk management
policy. The program is intended to manage the impact to earnings
caused by the volatility of energy prices by mitigating commodity
price risk, credit risk, and other risks related to the energy
commodity business. We discuss some of these risks later in Part
II Item 7 "Management's Discussion and Analysis of Financial
Conditions and Results of Operations - Market Risk."
The IPUC has approved our application to move our nonutility
electricity marketing activity from IPC to another IDACORP
subsidiary, IDACORP Energy. We expect to have FERC approval by
early April 2001. These non-operating transactions do not involve
sales from IPC's resources and are not related to system
reliability.
OTHER
Ida-West Energy Company
Ida-West develops, acquires, owns and manages electric power
projects. In January 2001, IPC chose Garnet Energy, a subsidiary
of Ida-West, to provide additional power that IPC is seeking to
secure. Garnet plans to build a 250-MW natural gas-fired turbine
near Middleton, Idaho, about 20 miles west of Boise. This plant
will have an upgrade potential to 500 MW and will be ready by mid-
2004 to meet IPC's projected need.
In March, 2000, Ida-West sold for cash its interest in the yet-to-
be-built Hermiston Power Project, a 536-MW gas-fired project to be
located near Hermiston, Oregon. Ida-West was responsible for
managing all permitting and development activities relating to the
project since its inception in 1993. Ida-West recorded a pre-tax
gain of $14 million on this transaction in 2000.
Ida-West has investments in 12 operating hydroelectric plants with
a total generating capacity of approximately 72 MW. IPC has
purchased all of the power from the five Idaho hydroelectric
entities that are fifty-percent owned by Ida-West, totaling
approximately $8.1 million in 2000.
Through September 1998, Ida-West was a subsidiary of IPC. On
October 1, 1998, Ida-West was transferred to become a direct
subsidiary of IDACORP.
IdaTech
In March 1999 IDACORP purchased a majority interest in IdaTech
(then known as Northwest Power Systems). IdaTech has patented a
unique fuel reformer that allows for the processing of a number of
fuels into hydrogen that is then used for the generation of
electricity. In 2000 IdaTech completed testing of its patented
alpha fuel cell system for residential applications, and is now
proceeding with design and production of the first 50 beta fuel
cell systems for testing in 2001, as agreed upon in a contract
with the Bonneville Power Administration. IdaTech also began
field testing its fuel cell systems in Japan in cooperation with
Tokyo Boeki, Ltd.
IdaTech is anticipating commercialization of its first units in
2002 in applications such as uninterruptible power sources and
emergency power. Residential units should be available in 2003.
Rocky Mountain Communications, Inc.
In August 2000, IDACORP acquired a controlling interest in Rocky
Mountain Communications, Inc. (RMCI), is a national Internet
service provider, offering traditional and high-speed Internet
access services in both residential and business markets.
RMCI is developing its high-speed Velocitus broadband wireless
Internet service for business applications and is marketing this
service to businesses across the western United States. The
service is currently available in Boise and Pocatello, Idaho and
Spokane, Washington, and is planned to be expanded to 70 cities
within the next two years.
Applied Power Company (APC)
In January 2001, IDACORP sold APC, a manufacturer, supplier and
distributor of solar photovoltaic systems. IPC had acquired APC
in 1996, and transferred ownership (at book value) to IDACORP on
January 1, 2000. APC was sold at approximately its book value.
IDACORP Financial Services (IFS)
IFS invests primarily in affordable housing projects, which
provide a return primarily by reducing federal income taxes
through tax credits and tax depreciation benefits. In 2000, IFS
expanded its portfolio to include historic rehabilitation projects
such as the El Cortez Hotel in San Diego, California and the
Empire Building in Boise. In January 2000, ownership of IFS was
transferred (at book value) from IPC to IDACORP.
IDACORP Services
IDACORP Services offers a variety of products and services to
residential and business customers. These offerings include: home
security monitoring, carbon monoxide detection, and home surge
protection devices, satellite dish products and services, payment
protection and appliance maintenance.
RESEARCH AND DEVELOPMENT
IdaTech owns several patents on a unique fuel reformer that allows
for the processing of a number of fuels into hydrogen that is then
used for the generation of electricity. In 2000, IdaTech spent
approximately $1.3 million for research and development of fuel
cell technology.
As an active member of the NEEA, IPC has been shifting the focus
of its conservation, or demand-side management (DSM), activities
towards regional market transformation efforts and renewing its
commitment to public purpose programs. At the same time, IPC has
discontinued many of the traditional DSM programs that required
deferral of costs. In 2000, $1.6 million was expended on energy-
efficiency programs.
During 2000, IPC spent approximately $0.1 million on research and
development through membership in Electric Power Research
Institute (EPRI). EPRI creates science technology solutions for
the global energy and energy service. Some of the subjects of
EPRI projects include: power quality, electric transportation
systems, EMF assessment/risk management and air quality issues.
CONSTRUCTION PROGRAM
IDACORP's construction and acquisition program for 2001-2005
(excluding allowances for funds used during construction) is
presently estimated to require cash funds of approximately $716
million as follows:
2001 2002-2005
(Millions of Dollars)
IPC Utility:
Generating facilities
Hydro $ 17.5 $ 67.9
Thermal 9.3 39.4
Total generating facilities 26.8 107.3
Transmission lines and substations 21.0 91.4
Distribution lines and substations 56.5 206.9
General 20.4 98.2
Total IPC cash construction 124.7 503.8
Energy marketing 7.2 7.4
Other 46.0 204.4
Total cash construction
expenditures $ 177.9 715.6
IPC has no nuclear involvement and its future construction plans
do not include development of any nuclear generation. IPC's
capital expenditures are primarily for maintaining current
infrastructures and meeting anticipated electricity demands.
Various options that may be available to meet the future energy
requirements of its customers including efficiency improvements on
IPC's generation, transmission and distribution systems and
purchased power and exchange agreements with other utilities or
other power suppliers. IPC will pursue the projects that best
meet its future energy needs.
FINANCING PROGRAM
The Company's five-year estimate of capital requirements and
sources of capital are outlined in the following table:
Idaho Power
IDACORP,Inc. * Company
2001 2002-2005 2001 2002-2005
(Millions of Dollars)
Capital Requirements:
Net cash construction
expenditure $ 124.7 $ 503.8 $ 124.7 $ 503.8
Other cash
expenditures 53.2 211.8 - -
Total $ 177.9 715.6 124.7 503.8
Sources of Capital:
Internal generation $ 177.9 640.3 124.7 428.1
Short-term bank loans
- net - 36.4 - 97.4
Other debt issued - 78.0 - (6.7)
Other - (39.1) - (15.0)
Total $ 177.9 715.6 124.7 503.8
*includes IPC
Capital expenditures are necessary to fund projects contributing
to the Company's earnings growth.
The above estimates are subject to constant revision in light of
changing economic, regulatory and environmental factors and
patterns of conservation. Any additional securities to be sold
will depend upon market conditions and other factors. The Company
will continue to take advantage of any refinancing opportunities
as they become available.
Under the terms of the Indenture relating to IPC's First Mortgage
Bonds, net earnings must be at least two times the annual interest
on all bonds and other equal or senior debt. For the twelve
months ended December 31, 2000, net earnings were 7.53 times.
Additional preferred stock may be issued when earnings for twelve
consecutive months within the preceding fifteen months are at
least equal to 1.75 times the aggregate annual interest
requirements on all debt securities and dividend requirements on
preferred stock. At December 31, 2000, the actual preferred
dividend earnings coverage was 3.98 times. If the dividends on
the shares of Auction Preferred Stock were to reach the maximum
allowed, the preferred dividend earnings coverage would be 3.05
times. The Indenture and IPC's Restated Articles of Incorporation
are exhibits to the Form 10-K and reference is made to them for a
full and complete statement of their provisions.
ITEM 2. PROPERTIES
IPC's system includes 17 hydroelectric generating plants located
in southern Idaho and eastern Oregon (detailed below) and an
interest in three coal-fired steam electric generating plants.
The system also includes approximately 4,656 miles of high voltage
transmission lines; 21 step-up transmission substations located at
power plants; 17 transmission substations; 7 transmission
switching stations; and 205 energized distribution substations
(excludes mobile substations and dispatch centers).
IPC holds licenses under the Federal Power Act for 13
hydroelectric projects from the FERC. These and the other
generating stations and their capacities are listed below:
Maximum
Non-
Coincident Nameplate
Operating Capacity License
Project Capacity kW kW Expiration
Properties Subject to
Federal Licenses:
Lower Salmon 70,000 60,000 1997 (a)
Bliss 80,000 75,000 1998 (a)
Upper Salmon 39,000 34,500 1998 (a)
Shoshone Falls 12,500 12,500 1999 (a)
C J Strike 89,000 82,800 2000 (a)
Upper Malad 9,000 8,270 2004
Lower Malad 15,000 13,500 2004
Brownlee-Oxbow-Hells
Canyon 1,398,000 1,166,900 2005
Swan Falls 25,547 25,000 2010
American Falls 112,420 92,340 2025
Cascade 14,000 12,420 2031
Milner 59,448 59,448 2038
Twin Falls 54,300 52,737 2041
Other Generating Plants:
Other Hydroelectric 10,400 11,300
Jim Bridger (coal-
fired) 706,667 709,617
Valmy (coal-fired) 260,650 260,650
Boardman (coal-fired) 55,200 56,050
(a)Renewed on a year-to-year basis; application for relicense is
pending.
At December 31, 2000, the composite average ages of the principal
parts of IPC's system, based on dollar investment, were:
production plant, 20 years; transmission system and substations,
20 years; and distribution lines and substations, 15 years. IPC
considers its properties to be well maintained and in good
operating condition.
IPC owns in fee all of its principal plants and other important
units of real property, except for portions of certain projects
licensed under the Federal Power Act and reservoirs and other
easements. IPC's property is also subject to the lien of its
Mortgage and Deed of Trust and the provisions of its project
licenses. In addition, IPC's property is subject to minor defects
common to properties of such size and character that do not
materially impair the value to, or the use by, IPC of such
properties.
As a result of various federal legislative actions and proposals
(such as the Electric Consumers Protection Act of 1986, Energy
Policy Act of 1992, Clean Water Act Reauthorization and Endangered
Species Act Reauthorization), a major issue facing IPC is the
relicensing of its hydro facilities. The relicensing of these
projects is not automatic under federal law. IPC must demonstrate
comprehensive usage of the facilities, that it has been a
conscientious steward of the natural resource entrusted to it, and
that it is in the public interest for IPC to continue to hold the
federal licenses.
IPC is actively pursuing new licenses for 10 of its 17
hydroelectric projects from the FERC. This process could take
anywhere from eight to 15 years, depending on environmental issues
and political processes.
The most significant relicensing will be the Hells Canyon Complex,
which provides over half of IPC's generation capacity. Presently,
IPC is developing study plans within the framework of a
collaborative team made up of individuals representing state and
federal agencies, businesses, environmental, tribal, customer,
local government and local landowner interests. IPC expects to
file the new license application in July 2003.
Shoshone Falls, Upper Salmon Falls, Lower Salmon Falls and Bliss
hydroelectric projects are awaiting an Environmental Impact
Statement (EIS) from the federal government, which is necessary
prior to license issuance. IPC completed 64 Additional
Information Requests (AIRs) from the agencies and non-governmental
organizations in early 2000, which combined with recently filed,
final recommendations, terms and conditions, will be used by the
FERC to produce a draft EIS for these projects in May 2001.
IPC filed its application for a new license for the C J Strike
project in November 1998. Similarly, 21 AIRs were issued on this
project as well and the FERC has noticed that this project is
Ready for Environmental Analysis which gives the agencies and
interested parties 60 days to provide their final recommendations,
terms and conditions for this project. A draft EIS is expected by
August 2001.
The Upper and Lower Malad projects, scheduled for a July 2002 new
license application, are nearing completion of field studies and
reporting should be complete in early 2001.
Idaho Energy Resources Co. owns a one-third interest in certain
coal leases near the Jim Bridger generating plant in Wyoming from
which coal is mined and supplied to the plant.
Ida-West holds investments in 12 operating hydroelectric plants
with a total generating capacity of 72 MW.
ITEM 3. LEGAL PROCEEDINGS
None
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None
EXECUTIVE OFFICERS OF THE REGISTRANT
The names, ages and positions of all of the executive officers of
IDACORP, Inc. are listed below along with their business
experience during the past five years. There are no family
relationships among these officers, nor any arrangement or
understanding between any officer and any other person pursuant to
which the officer was elected.
IDACORP, Inc.
Name, Age and Position Business Experience During Past Five (5) Years*
Jan B. Packwood, 57 Appointed May 30, 1999. Mr.
President and Chief Packwood was President and Chief
Executive Officer Operating Officer from February 2,
1998 to May 30, 1999.
J. LaMont Keen, 48 Appointed May 5, 1999. Mr. Keen was
Senior Vice President, Senior Vice President-Administration,
Administration and Chief Chief Financial Officer and Treasurer
Financial Officer from March 15, 1999 to May 5, 1999,
and Vice President, Chief Financial
Officer and Treasurer from February
2, 1998 to March 15, 1999.
Richard Riazzi, 46 Appointed March 15, 1999. Mr. Riazzi
Senior Vice President, was Vice President - Marketing and
Generation and Marketing Sales from January 14, 1999 to March
15, 1999.
Darrel T. Anderson, 42 Appointed May 5, 1999.
Vice President-Finance
and Treasurer
Robert W. Stahman, 56 Appointed February 2, 1998.
Vice President-General
Counsel and Secretary
________________
*IDACORP, Inc. executive officers serve in the same capacities at
Idaho Power Company. For these officers' business experience
during the past five years, please refer to the next table.
EXECUTIVE OFFICERS OF THE REGISTRANT
The names, ages and positions of all of the executive officers of
Idaho Power Company are listed below along with their business
experience during the past five years. There are no family
relationships among these officers, nor any arrangement or
understanding between any officer and any other person pursuant to
which the officer was elected.
Idaho Power Company
Name, Age and Position Business Experience During Past Five (5) Years
Jan B. Packwood, 57 Appointed May 30, 1999. Mr. Packwood
President and Chief was President and Chief Operating
Executive Officer Officer from September 1, 1997 to May
30, 1999, Executive Vice President
from July 11, 1996 to September 1,
1997, and Vice President-Power Supply
prior to July 11, 1996.
J. LaMont Keen, 48 Appointed May 5, 1999. Mr. Keen was
Senior Vice President - Senior Vice President-Administration,
Administration and Chief Chief Financial Officer and Treasurer
Financial Officer from March 15, 1999 to May 5, 1999,
Vice President, Chief Financial
Officer and Treasurer from March 14,
1996 to March 15, 1999 and Vice
President and Chief Financial Officer
prior to March 14, 1996.
James C. Miller, 46 Appointed November 18, 1999. Mr.
Senior Vice President - Miller was Vice President -
Delivery Generation from July 10, 1997 to
November 18, 1999 and was General
Manager - Generation prior to July
10, 1997.
Richard Riazzi, 46 Appointed March 15, 1999. Mr. Riazzi
Senior Vice President - was Vice President - Marketing and
Generation and Marketing Sales from January 9, 1997 to March
15, 1999. Mr. Riazzi was Vice
President, Corporate Marketing (1995-
1996) for Equitable Resources, Inc.
Darrel T. Anderson, 42 Appointed May 5, 1999. Mr. Anderson
Vice President - Finance was corporate controller from January
and Treasurer 25, 1999 to May 5, 1999, Executive
Vice President of Finance and
Operations at Applied Power Corp.
from June 5, 1998 to January 25,
1999, and corporate controller from
February 26, 1996 to June 5, 1998.
Mr. Anderson was Senior Manager of
Audit Services for Deloitte & Touche
LLP prior to February 26, 1996.
John P. Prescott, 44 Appointed November 18, 1999. Mr.
Vice President - Prescott was Vice President of
Generation Business Development for IDACORP
Technologies, Inc. from August 1999
to November 18, 1999, and President
and Treasurer of Stellar Dynamics
from October 5, 1995 to August 1999.
Bryan A.B. Kearney, 38 Appointed November 18, 1999. Mr.
Vice President and Chief Kearney was Vice President and Chief
Information Officer Technology Officer at Bear Creek Corp
(1998-1999), Chief Information
Officer for Shasta County, California
(1996-1998), and Director of
Information Systems and Services for
the City of Fort Worth, Texas (1994-
1995).
Cliff N. Olson, 51 Appointed July 11, 1991.
Vice President -
Corporate Services
Robert W. Stahman, 56 Appointed July 13, 1989.
Vice President - General
Counsel and Secretary
Marlene K. Williams, 48 Appointed May 5, 1999. Ms. Williams
Vice President - Human was Director of Human Resources at
Resources Arizona Public Service prior to May
5, 1999.
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON STOCK AND RELATED
STOCKHOLDER MATTERS
IDACORP, Inc.'s common stock (without par value) is traded on the
New York and Pacific Stock Exchanges. At December 31, 2000, there
were 21,886 holders of record and the year-end stock price was
$49.06 per share.
The outstanding shares of Idaho Power Company common stock ($2.50
par value) are held by IDACORP, Inc. and are not traded. IDACORP,
Inc. became the holding company of Idaho Power Company on October
1, 1998.
The following table shows the reported high and low sales price
and dividends paid for the years 2000 and 1999 as reported by the
Wall Street Journal as composite tape transactions.
2000 Quarters
Common Stock, without par
value: 1st 2nd 3rd 4th
High $53.00 $37.00 $48.69 $51.81
Low 25.94 31.00 32.38 43.38
Dividends paid per
share (cents) 46.5 46.5 46.5 46.5
______________________________
1999 Quarters
Common Stock, without par
value: 1st 2nd 3rd 4th
High $36.50 $33.63 $32.00 $31.25
Low 29.25 29.50 29.19 26.00
Dividends paid per
share (cents) 46.5 46.5 46.5 46.5
ITEM 6. SELECTED FINANCIAL DATA
SUMMARY OF OPERATIONS (Thousands of Dollars except for per share amounts)
IDACORP, Inc.
For the Years Ended
December 31, 2000 1999 1998 1997 1996
Operating revenues $1,019,353 $ 731,152 $ 795,087 $ 627,724 $ 598,065
Income from operations 261,663 199,050 193,423 191,746 193,768
Net income 139,883 91,349 89,176 87,098 83,155
Earnings per average
share outstanding
(basic and diluted) 3.72 2.43 2.37 2.32 2.21
Dividends declared per
share 1.86 1.86 1.86 1.86 1.86
At December 31,
Total long-term debt* 864,114 821,558 815,937 746,142 769,810
Total assets 4,639,258 2,640,371 2,456,819 2,451,816 2,328,738
*Excludes amount due within one year.
The above data should be read in conjunction with IDACORP's
consolidated financial statements and notes to consolidated
financial statements included in this Annual Report on Form 10-K.
SUMMARY OF OPERATIONS (Thousands of Dollars)
IDAHO POWER COMPANY
For the Years Ended 2000 1999 1998 1997 1996
December 31,
Operating revenues $ 835,662 $ 658,336 $ 756,410 $ 605,183 $ 578,445
Income from operations 169,636 172,458 180,584 180,731 187,171
Net income 131,559 97,528 95,919 92,274 90,618
At December 31,
Total long-term debt* 808,977 821,558 815,937 746,142 769,810
Total assets 4,295,098 2,559,374 2,421,790 2,451,816 2,328,738
Utility Customer Data:
General business
customers 393,831 384,421 373,730 363,085 352,487
Average kWh per customer 37,068 36,379 36,368 37,080 37,627
Average rate per kWh (cents) 3.87 3.75 3.85 3.63 3.71
*Excludes amount due within one year.
The above data should be read in conjunction with Idaho Power
Company's consolidated financial statements and notes to
consolidated financial statements included in this Annual Report
on Form 10-K.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
INTRODUCTION
In Management's Discussion and Analysis we explain the general
financial condition and results of operations of IDACORP, Inc. and
its subsidiaries (IDACORP or the Company). IDACORP is a holding
company formed in 1998 as the parent of Idaho Power Company (IPC),
and several other entities.
IPC is an electric utility with a service territory covering over
20,000 square miles, primarily in southern Idaho, and eastern
Oregon. IPC also conducts electricity marketing and trading
operations, and is the parent of Idaho Energy Resources Co., a
joint venturer in Bridger Coal Company, which supplies coal to
IPC's Jim Bridger generating plant.
IDACORP's other significant operating subsidiaries are:
IDACORP Energy Services - natural gas marketing
Ida-West Energy - independent power projects development and
management
IdaTech - developer of integrated fuel cell systems
IDACORP Financial Services - affordable housing and other real
estate investments
Rocky Mountain Communications- commercial and residential
Internet service provider
IDACOMM - provider of telecommunications services
IDACORP Services - energy related products and services
Applied Power Company - supplier of photovoltaic systems (sold
January 2001).
As you read Management's Discussion and Analysis, it may be
helpful to refer to our Consolidated Statements of Income which
present our results of operations for the years ended December 31,
2000, 1999 and 1998. In our discussion we explain, by operating
segment, the significant annual changes between specific line
items in the Consolidated Statements of Income.
FORWARD-LOOKING INFORMATION
In connection with the safe harbor provisions of the Private
Securities Litigation Reform Act of 1995 (Reform Act), we are
hereby filing cautionary statements identifying important factors
that could cause our actual results to differ materially from
those projected in forward-looking statements (as such term is
defined in the Reform Act) made by or on behalf of the Company in
this Annual Report, any quarterly report on Form 10-Q, in
presentations, in response to questions or otherwise. Any
statements that express, or involve discussions as to
expectations, beliefs, plans, objectives, assumptions or future
events or performance (often, but not always, through the use of
words or phrases such as "anticipates", "believes", "estimates",
"expects", "intends", "plans", "predicts", "projects", "will
likely result", "will continue", or similar expressions) are not
statements of historical facts and may be forward-looking.
Forward-looking statements involve estimates, assumptions, and
uncertainties and are qualified in their entirety by reference to,
and are accompanied by, the following important factors, which are
difficult to predict, contain uncertainties, are beyond our
control and may cause actual results to differ materially from
those contained in forward-looking statements:
prevailing governmental policies and regulatory actions,
including those of the Federal Energy Regulatory Commission (FERC),
the Idaho Public Utilities Commission (IPUC), the Oregon Public
Utilities Commission (OPUC), and the Public Utilities Commission of
Nevada (PUCN), with respect to allowed rates of return, industry and
rate structure, acquisition and disposal of assets and facilities,
operation and construction of plant facilities, recovery of
purchased power and other capital investments, and present or
prospective wholesale and retail competition (including but not
limited to retail wheeling and transmission costs);
the current energy situation in the western United States;
economic and geographic factors including political and
economic risks;
changes in and compliance with environmental and safety laws
and policies;
weather conditions;
population growth rates and demographic patterns;
competition for retail and wholesale customers;
pricing and transportation of commodities;
market demand, including structural market changes;
changes in tax rates or policies or in rates of inflation;
changes in project costs;
unanticipated changes in operating expenses and capital
expenditures;
capital market conditions;
competition for new energy development opportunities; and
legal and administrative proceedings (whether civil or
criminal) and settlements that influence the business and
profitability of the Company.
Any forward-looking statement speaks only as of the date on which
such statement is made, and we undertake no obligation to update
any forward-looking statement to reflect events or circumstances
after the date on which such statement is made or to reflect the
occurrence of unanticipated events. New factors emerge from time
to time and it is not possible for management to predict all such
factors, nor can it assess the impact of any such factor on the
business or the extent to which any factor, or combination of
factors, may cause results to differ materially from those
contained in any forward-looking statement.
RESULTS OF OPERATIONS
In this section we discuss our earnings and the factors that
affected them, beginning with a general overview and then
discussing results for each of our operating segments.
Earnings per share of
common stock
2000 1999 1998
Utility operations $ 1.97 $ 2.00 $ 2.13
Energy marketing 1.58 0.34 0.14
Other 0.17 0.09 0.10
Total earnings per
share $ 3.72 $ 2.43 $ 2.37
Return on year-end
common equity 17.0% 12.1% 12.2%
The primary factor contributing to the increases in earnings per
share (EPS) from 1999 to 2000 and from 1998 to 1999 is favorable
energy marketing results. Our net income from energy marketing
increased $47 million in 2000 and $8 million in 1999 due to a
combination of factors, including increased price volatility in
the energy markets, and increased trading volumes over a larger
geographic area.
The decrease in EPS from utility operations from 1999 to 2000 is
predominantly the result of increased net power supply costs, due
to a decline in hydroelectric generating conditions and increased
market prices for purchased power. These cost increases are
partially offset by increased general business revenue resulting
from rate increases, customer growth and weather conditions.
EPS from utility operations was less in 1999 compared to 1998 due
primarily to increased costs at our coal-fired generations plant
and payroll and consulting expenses.
Our EPS from other operations increased in 2000 compared to 1999,
predominantly because of the gain recorded on the sale in March
2000 of the Hermiston Power Project. This gain was partially
offset by losses related to newly acquired subsidiaries.
UTILITY OPERATIONS
This section discusses IPC's utility operations, which are subject
to regulation by, among others, the state public utility
commissions of Idaho, Oregon, and Nevada, and by the Federal
Energy Regulatory Commission. Before we discuss the changes in
income from our utility operations, we'll describe these
operations to help you understand them and the relationship
between the financial statement line items.
IPC owns and operate 17 hydroelectric power plants and shares
ownership in three coal-fired generating plants. The following
table presents IPC's system generation for the last three years:
MWhs (in thousands) Percent of total
generation
2000 1999 1998 2000 1999 1998
Hydroelectric 8,500 10,652 11,135 52% 59% 62%
Thermal 7,701 7,266 6,925 48 41 38
Total system
generation 16,201 17,918 18,060 100% 100% 100%
Hydro generation was seven percent below normal conditions in
2000, 17 percent above normal in 1999 and 22 percent above normal
in 1998.
Because of its reliance on hydroelectric generation, IPC's
generation operations can be significantly affected by the
weather. The availability of inexpensive hydroelectric power
depends on snowpack in the mountains above IPC's hydro facilities,
precipitation and other weather and streamflow management
considerations. When hydroelectric generation decreases and
customer demand increases, as it has from 1998 to 2000, we must
increase our reliance on more expensive thermal generation and
purchased power.
The rates we charge to our general business customers are
determined by the various regulatory authorities. Approximately
95 percent of our general business revenue and sales come from
customers in the state of Idaho. The rates we charge these
customers, (except for customers with special contracts) are
adjusted annually by a power cost adjustment (PCA) mechanism. The
PCA adjusts rates to reflect the changes in costs incurred by IPC
to supply power. Throughout the year, we compare our actual power
supply costs to the amounts we are recovering in rates. Most, but
not all, of this difference is deferred and included in the
calculation of rates for future years.
The primary influences on electricity sales are weather and
economic conditions. Generally, extreme temperatures increase
sales to customers, who use electricity for cooling and heating,
and moderate temperatures decrease sales. Precipitation levels
during the growing season affect sales to customers who use
electricity to operate irrigation pumps. Increased precipitation
reduces electricity usage by these customers.
Strong overall economic conditions in our utility service
territory have resulted in general business customer growth, with
2.4 percent, 2.9 percent and 2.9 percent increases in average
customers served in 2000, 1999, and 1998 respectively.
General Business Revenue
The following table presents IPC's general business revenues and
volumes for the last three years:
Revenues Volumes
(in thousands of dollars) (in thousands of MWh)
2000 1999 1998 2000 1999 1998
Residential $225,336 $213,547 $211,445 4,393 4,200 4,090
Commercial (less
than 1000 kW demand) 129,816 120,846 118,375 3,375 3,164 2,997
Industrial (greater
than 1000 kW demand) 133,171 117,366 124,237 4,808 4,666 4,788
Irrigation 74,827 62,166 58,639 1,993 1,706 1,466
Public Highway and
Street 2,207 2,223 2,160 29 30 28
Total $565,357 $516,148 $514,856 14,598 13,766 13,369
As mentioned above, our general business revenue is dependent on
many factors, including the number of customers we serve, the
rates we charge, and weather conditions.
2000 vs. 1999
The 9.5 percent increase in general business revenues is due to
the following factors:
Increased average rates, resulting from the PCA and special-
contract customers, increased revenues $17 million. We discuss the
PCA in more detail below in "Regulatory Issues - Power Cost
Adjustment";
Increased usage per customer, resulting from weather conditions
and other factors, increased revenues $26 million. Decreased
precipitation during the growing season increased sales to
irrigation customers, and hotter summer and colder winter
temperatures increased sales to the other customer classes;
Our average number of customers increased 2.7 percent over
1999, increasing revenue $6 million.
1999 vs. 1998
In 1999, general business revenue was only marginally higher than
1998. The following factors influenced general business revenue:
A 2.9 percent increase in general business customers increased
revenue $7 million;
Drier weather conditions and other factors affecting usage
increased revenue $12 million;
Decreased average rates, resulting from the PCA, decreased
revenue $17 million.
Off-system sales
Off-system sales consist primarily of long-term sales contracts
and opportunity sales of surplus system energy.
$ (in thousands) MWh (in thousands) Revenue per MWh
2000 1999 1998 2000 1999 1998 2000 1999 1998
$229,986 $119,785 $214,418 4,529 5,924 7,907 $50.78 $20.22 $27.12
2000 vs. 1999
Off-system sales increased due predominantly to significant
increases in prices for surplus system energy, which increased our
average revenue per MWh by over 150 percent. A 24 percent
decrease in volumes of electricity sold, due to decreased
availability, partially offset the increase in market prices.
1999 vs. 1998
Off system sales decreased due principally to two factors, a 25
percent decrease in volumes sold and a 25 percent decrease in
price per MWh.
Power Supply
The Power supply components of income from operations include off-
system sales (described and analyzed above) and purchased power,
fuel and PCA expenses (analyzed below).
The impact of the changes in net power supply costs was an
increase in net power supply expense of $69 million in 2000 and a
decrease of $6 million in 1999. The PCA adjustment is not
designed to fully mitigate the effect of fluctuations in net power
supply costs, and is applicable only to Idaho customers.
Purchased power
$ (in thousands) MWh (in thousands) Cost per MWh
2000 1999 1998 2000 1999 1998 2000 1999 1998
$398,649 $106,344 $185,271 4,311 3,127 4,707 $92.47 $34.01 $39.36
2000 vs. 1999
Purchased power expenses increased $292 million in 2000 due to
major increases in prices in the energy markets, and to increased
volumes purchased. The increase in volumes was necessitated by
decreased generation at our hydroelectric plants and increased
customer demand.
1999 vs. 1998
Purchased power expenses decreased $79 million in 1999.
Contributing to these results are a number of operational factors,
including changing hydro availability, system load and fluctuating
wholesale market conditions.
Fuel expense
$ (in thousands) Thermal MWh generated
(in thousands)
2000 1999 1998 2000 1999 1998
$94,215 $86,617 $86,237 7,701 7,266 6,925
2000 vs. 1999
Fuel expenses increased by $8 million in 2000, due primarily to
increased generation at our coal-fired plants, necessitated by
decreased generation at our hydroelectric plants and increased
customer demand.
1999 vs. 1998
Fuel expenses were essentially unchanged. Increases in generation
were offset by decreased average coal prices.
Power Cost Adjustment
The PCA component of expenses is related to the Company's PCA
regulatory mechanism. The PCA mechanism increases expenses when
power supply costs are below forecast, and decreases expenses when
power supply costs are above forecast. We discuss the PCA in more
detail in "Regulatory Issues - Power Cost Adjustment."
2000 vs. 1999
The PCA expense was a credit of $121 million in 2000, due
predominantly to the considerable increases in purchased power
costs not anticipated in our 2000-2001 rate year forecast. In
1999, actual power supply costs were near forecast, causing the
PCA component of expense to be minimal.
1999 vs. 1998
The PCA decreased $22 million in 1999, due to 1999's power supply
costs being near forecast, while 1998 costs were below forecast.
Other Expenses
2000 vs. 1999
Other operations and maintenance expenses in 2000 were
substantially unchanged from 1999. Decreased pension expenses
were offset by increased distribution line maintenance and general
expenses. Depreciation expenses increased $2 million, primarily
due to plant additions.
1999 vs. 1998
Other operations and maintenance expenses increased $6 million in
1999. The increase was principally due to increased operating
expenses at our coal-fired generation plants, and payroll and
consulting expenses. Depreciation expenses increased $3 million,
due primarily to plant additions.
ENERGY MARKETING
To compete as an energy provider of choice, we have built a
trading operation that participates in the electricity, natural
gas and other related markets from our offices in Boise, Idaho and
Houston, Texas. Our energy marketing and trading strategy has
produced increasingly positive results over the last four years.
Our natural gas marketing capability continues to expand as the
electricity and natural gas markets move toward convergence, and
our electricity marketing efforts have resulted in volume and
income increases each year since inception of the strategy.
When buying and selling energy, the high volatility of energy
prices can have significant negative impact on profitability if
not appropriately managed. Also, counterparty creditworthiness is
key to ensuring that transactions entered into withstand dramatic
market fluctuations. To manage the risks inherent in the energy
commodity industry while implementing our business strategy, our
Risk Management Committee, comprised of Company officers, oversees
the risk management program as defined in our risk management
policy. The program is intended to manage the impact to earnings
caused by the volatility of energy prices by mitigating commodity
price risk, credit risk, and other risks related to the energy
commodity business. We discuss some of these risks later in
"Market Risk."
In August 2000 the IPUC approved our application to move our
nonutility electricity marketing activity to another IDACORP
subsidiary, IDACORP Energy. We expect to have FERC approval by
early April 2001. These non-operating transactions do not involve
sales from IPC's resources and are not related to system
reliability.
Operating Revenues
2000 vs. 1999
Energy marketing revenues increased $114 million in 2000 due
primarily to increased prices in the energy markets and increased
marketing activity. The market conditions in 2000 were something
of an anomaly and as such, we do not anticipate that revenues will
continue to grow at the rate seen in 2000. We anticipate our
marketing revenues to grow in relation to the base 1999 revenues.
1999 vs. 1998
Energy marketing revenues increased $21 million in 1999 due
primarily to increased energy marketing activities.
Operating Expenses
2000 vs. 1999
Energy marketing expenses increased $41 million in 2000 due
primarily to increased administrative expenses related to the
increased marketing activities. This includes increased credit
reserves to reflect, in part, the increased risk associated with
transactions with the California Power Exchange and Independent
System Operator. We have approximately $48 million of receivables
from these entities and have set up reserves in accordance with
our credit policies reflective of the increased credit risk in
these markets.
The Risk Management Policy defines market risk limits within which
trading must be contained. Also, included is an extensive credit
policy within which each counterparty is evaluated for financial
strength and assigned a credit limit. Credit exposure with each
counterparty is measured daily as well as the credit exposure of
the entire portfolio. Our strategy is to diversify credit risk
across counterparties and to set up appropriate credit reserves to
protect against the potential credit losses in the portfolio.
1999 vs. 1998
Energy marketing expenses increased $7 million in 1999 due
primarily to increased energy marketing activities.
OTHER OPERATIONS
Other operations include the results of operations of our
diversified subsidiaries, including Ida-West Energy Company;
IdaTech, LLC; Applied Power Company (APC); IDACORP Financial
Services; IDACORP Services Co.; IDACOMM, Inc.; and Rocky Mountain
Communications, Inc. (RMCI).
Revenues
2000 vs. 1999
Other diversified operating revenues decreased $5 million in 2000
due primarily to a reduction in sales made by APC.
1999 vs. 1998
Other diversified revenues increased $14 million in 1999 due
primarily to revenues of businesses acquired by APC in 1998 and
1999.
Expenses
2000 vs. 1999
Other diversified operating expenses increased $4 million in 2000
due primarily to the operations of RMCI, acquired in August 2000,
and increased activities at IdaTech, our fuel-cell technology
development subsidiary, offset by a reduction in expenses at APC.
1999 vs. 1998
Other diversified operating expenses increased $13 million in 1999
due primarily to expense of businesses acquired by APC in 1998 and
1999.
Other Income
2000 vs. 1999
Other income increased $11 million in 2000 due primarily to the
sale of our interest in the Hermiston Power Project, a 536-MW, gas-
fired cogeneration project to be located near Hermiston, Oregon.
Ida-West Energy Company, a wholly owned subsidiary of IDACORP, was
responsible for managing all permitting and development activities
relating to the project since its inception in 1993. We recorded
a pre-tax gain of $14 million on this transaction.
LIQUIDITY AND CAPITAL RESOURCES
Cash Flow
Our net cash generated from operations totaled $534 million for
the three-year period 1998-2000. After deducting common dividends
of $210 million, net cash generation from operations provided
approximately $324 million for our construction program and other
capital requirements. Internal cash generation after dividends
provided 42 percent of our total capital requirements in 2000, 114
percent in 1999, and 95 percent in 1998. Operating cash flows
declined in 2000, predominantly due to the growth in our PCA
regulatory asset balance, reflecting increased power supply
expenditures that we have not yet recovered through PCA rate
adjustments.
We forecast that internal cash generation after dividends will
provide approximately 101 percent of total capital requirements in
2001 and 109 percent during the four-year period 2002-2005. We
expect to continue financing our utility construction program and
other capital requirements with both internally generated funds
and, to the extent necessary, externally financed capital.
Principal amounts of long-term debt maturing in the next five
years are as follows (in millions of dollars):
2001 2002 2003 2004 2005
Utility $30.1 $27.1 $80.1 $50.1 $60.1
Other 9.7 9.5 9.2 9.3 8.3
At January 1, 2001, IPC had regulatory authority to incur up to
$200 million of short-term indebtedness. At December 31, 2000,
IPC's short-term borrowing totaled $60 million compared to $20
million at December 31, 1999, and $39 million at December 31,
1998.
We have credit facilities established at both IPC and IDACORP.
IPC has a $120 million multi-year revolving credit facility under
which we pay a facility fee on the commitment, quarterly in
arrears, based on IPC's First Mortgage Bond Rating. Commercial
paper may be issued subject to the regulatory maximum, and is
supported by bank lines of credit of an equal amount.
IDACORP has separately established a $50 million three-year credit
facility that expires in December 2001, and a $100 million 364-day
credit facility that expired in February 2001. We have
established a new 364-day credit facility for up to $375 million
to help support our unregulated operations. Under these
facilities we pay a facility fee on the commitment, quarterly in
arrears, based on IPC's First Mortgage Bond Rating. Commercial
paper may be issued up to the amounts supported by the bank credit
facilities. (See Note 7 of "Notes to Consolidated Financial
Statements"). At December 31, 2000, IDACORP's short-term
borrowing totaled $61 million.
Construction Program
Our consolidated cash construction expenditures totaled $140
million in 2000, $111 million in 1999, and $89 million in 1998.
Approximately 29 percent of these expenditures were for generation
facilities, 21 percent for transmission facilities, 36 percent for
distribution facilities, and 14 percent for general plant and
equipment.
We estimate that our cash construction and acquisition programs
will require the following amounts over the next five years.
These estimates are subject to revision in light of changing
economic, regulatory, environmental, and conservation factors.
2001 2002-2005
(In millions of $)
Utility $124.7 $503.8
Energy marketing 7.2 7.4
Other 46.0 204.4
Total $177.9 $715.6
Financing Program
Our consolidated capital structure fluctuated slightly during the
three-year period, with common equity ending at 46 percent,
preferred stock (of IPC) 6 percent, and long-term debt 48 percent
at December 31, 2000.
IDACORP, Inc. currently has a $300 million shelf registration
statement that can be used for the issuance of unsecured debt
securities and preferred or common stock. At December 31, 2000,
none had been issued.
In March 2000 IPC filed a $200 million shelf registration
statement that can be used for both first mortgage bonds
(including medium-term notes), preferred stock and unsecured debt.
In December 2000, $80 million of Secured Medium Term Notes were
issued by IPC. Proceeds from this issuance were used in January
2001 for the early redemption of $75 million of First Mortgage
Bonds originally due in 2021. At December 31, 2000, $120 million
of the total remained to be issued.
In April 2000, at our request, the American Falls Reservoir
District issued its American Falls Refunding Replacement Dam
Bonds, Series 2000. Proceeds from issuance of these bonds, in the
aggregate amount of $19.9 million, were used to refund the same
amount of bonds dated May 1, 1990. IPC has guaranteed repayment
of these bonds.
In May 2000 $4.4 million of tax-exempt Pollution Control Revenue
Refunding Bonds were issued by Port of Morrow, Oregon. Proceeds
were used to refund in August 2000 the same amount of Pollution
control Revenue Bonds, Series 1978.
In November 1999 IPC issued $80 million of Secured Medium Term
Notes. The proceeds from this issuance were used in January 2000
to redeem at maturity $80 million of First Mortgage Bonds.
In September 1998 IPC issued $60 million of Secured Medium Term
Notes. The proceeds from this issuance were used to redeem at
maturity $30 million of First Mortgage Bonds, and to reduce the
balance of commercial paper issued in connection with ongoing
business.
CURRENT ISSUES
In this section we address a number of other issues that affect or
could affect our operations.
Western Electricity Markets and California Energy Situation
Our utility operations are being affected by the electricity
market conditions in the western United States. The tremendous
increase in prices for purchased power, along with increasing
demand and reduced hydroelectric generation, have combined to
produce substantial increases in our costs to supply power.
The current mountain snowpack above Brownlee Reservoir, our main
storage pool for our Hells Canyon hydro facilities, was at 55
percent of normal in February 2001. This indicates that our
hydroelectric generation could be appreciably diminished in 2001.
In May 2001, we will implement the annual PCA adjustment in Idaho
to recover up to 90% of our costs to supply power in the Idaho
jurisdiction. The cost recovery mechanism is based on the
forecast for the May 2001-May 2002 period and a true-up for the
preceding year. Because the resulting rate increases are expected
to be large, we are exploring an alternative method of cost
recovery with the Idaho Public Utilities Commission and the
legislature. This method, if approved and implemented, would
enable us to recover the costs up front but spread the impact on
our customers out over a longer period of time.
We are also proposing a number of programs to decrease our
reliance on expensive wholesale power. The programs are designed
to reduce overall energy usage, decrease peak-demand levels and
increase generation within our service territory.
With regard to our non-utility energy trading in the state of
California, IPC in January 1999 entered into a Participation
Agreement with the California Power Exchange (CalPX), a California
non-profit public benefit corporation. The CalPX operates a
wholesale electricity market in California by acting as a
clearinghouse through which electricity is bought and sold.
Pursuant to the Participation Agreement, IPC could sell power to
the CalPX under the terms and conditions of the CalPX Tariff.
On January 18, 2001, the CalPX sent us an invoice for $2.2 million
- - a "default share invoice" - as a result of an alleged Southern
California Edison (SCE) payment default of $214.5 million for
power purchases. We made this payment. On January 24, 2001, we
terminated our Participation Agreement with the CalPX. On
February 8, 2001, the CalPX sent a further default share invoice
for $5.2 million, due February 20, 2001, as a result of alleged
payment defaults by SCE and Pacific Gas and Electric Company
(PG&E), and others. However, the CalPX owes us $11.3 million for
power sold to the CalPX in November and December 2000. We did not
pay the February 8 invoice.
The CalPX allocated the defaults of, among others, SCE and PG&E to
the remaining participants based upon the level of trading
activity of each participant during the preceding three-month
period. IPC believes that the default invoices were not proper
and that it owes no further amounts to the CalPX. IPC intends to
pursue all available remedies in its efforts to collect amounts
owed to it by the CalPX.
In addition to the amounts due us from the CalPX, IPC is currently
owed approximately $36.5 million from the Cal ISO for sales in November
and December 2000.
On February 20, we filed a petition with FERC to intervene in a
proceeding which requests the FERC to suspend the use of the CalPX
charge back methodology and provides for further FERC oversight in
the CalPX's implementation of its default mitigation procedures.
Also a preliminary injunction has been granted by a Federal Judge
in the Federal District Court for the Central District of
California enjoining the CalPX from declaring any CalPX
participant in default under the terms of the CalPX Tariff. On March
9,2001, the CalPX filed for Chapter 11 protection with the U.S.
Bankruptcy Court, Central District of California.
We are unable to predict the outcome of these situations.
In California, the Company believes that it has credit exposure in
the range of $30-40 million. The Company continues to manage this
exposure in accordance with established credit policies.
Regulatory Issues
Power Cost Adjustment (PCA)
IPC has a PCA mechanism that provides for annual adjustments to
the rates we charge to our Idaho retail customers. These
adjustments, which take effect annually in mid-May, are based on
forecasts of net power supply costs, and the true-up of the prior
year's forecast. The difference between the actual costs incurred
and the forecasted costs is deferred, with interest, and trued-up
in the next annual rate adjustment.
Our May 2000 rate adjustment increased Idaho general business
customer rates by 9.5 percent, and resulted from forecasted below-
average hydroelectric generating conditions. Overall, IPC's
annual general business revenues are expected to increase $38
million during the 2000-2001 rate period.
So far in the 2000-2001 rate period actual power supply costs have
been significantly greater than the forecast, due to actual hydrolectric
conditions being below the forecast, and purchased power prices being
significantly above the forecast. To account for these higher-than-
forecasted costs, IPC has recorded a regulatory asset of $120 million
as of December 31, 2000 ($161 million as of January 31, 2001). In
February, 2001 IPC filed an application with the IPUC proposing to
implement a one-year emergency fuel charge due to these extraordinarily
high expenses. The IPUC suspended the proposed effective date of March
26, 2001 to May 1, 2001, to allow for public workshops and hearings to
be held on the matter. The IPUC also ordered IPC to make its annual PCA
filing as soon as possible so that the cases can be filed jointly. IPC
will be making its filing at the end of March 2001. Due to the overall
weakness in the general credit markets across the United States, and
concerns regarding the liquidity of the western energy markets, any
negative indication by regulators regarding the recovery of wholesale
purchased power costs would affect our ability to successfully access the
credit markets.
The May 1999 rate adjustment reduced rates by 9.2 percent. The
decrease was the result of both forecasted above-average
hydroelectric generating conditions and a true-up from the 1998-99
rate period. Overall, the May 1999 rate adjustment decreased
annual general business revenues by $40 million during the 1999-
2000 rate period.
Regulatory Settlement
IPC had a settlement agreement with the IPUC that expired at the
end of 1999. Under the terms of the settlement, when earnings in
our Idaho jurisdiction exceeded an 11.75 percent return on year-
end common equity, we set aside 50 percent of the excess for the
benefit of our Idaho retail customers.
In March 2000 we submitted our 1999 annual earnings sharing
compliance filing to the IPUC. This filing indicated that there
was almost $9.6 million in 1999 earnings and $2.7 million in
unused 1998 reserve balances available for the benefit of our
Idaho customers.
In April 2000 the IPUC ordered that $6.9 million of the revenue
sharing balance be refunded to Idaho customers through rate
reductions effective May 16, 2000 thus reducing the effect of the
PCA on revenues and customer rates. The IPUC also approved IPC's
continuing participation in the Northwest Energy Efficiency
Alliance (NEEA) through 2004, ordering IPC to set aside the
remaining $5.4 million of revenue sharing dollars to fund that
participation.
Demand-Side Management (Conservation) Expenses
IPC requested that the IPUC allow for the recovery of post-1993
DSM expenses and acceleration of the recovery of DSM expenditures
authorized in the last general rate case. The IPUC set a new
amortization period of 12 years instead of the 24-year period
previously established. The order reflects an increase in annual
Idaho retail revenue requirements of $3.1 million for 12 years.
On April 17, 2000, the Idaho Supreme Court affirmed the IPUC
order, after hearing an appeal by a group of industrial customers.
Electric Industry Restructuring
Competition is increasing in the electric utility industry. Our
goal is to anticipate and fully integrate into our operations any
legislative, regulatory or competitive changes.
In 1997, the Idaho Legislature appointed a committee to study
restructuring of the electric utility industry. Although the
committee will continue studying a variety of restructuring ideas,
it has not recommended any restructuring legislation and is not
expected to in the foreseeable future.
In 1999, the Oregon legislature passed legislation restructuring
the electric utility industry, but exempted IPC's service
territory.
Integrated Resource Plan (IRP)
Every two years, IPC is required to file with the IPUC and OPUC an
IRP, a comprehensive look at IPC's present and future demands for
electricity and plan for meeting that demand. The 2000 IRP
identifies a potential electricity shortfall within our utility
service territory by mid-2004. The plan projects a 250-MW
resource need in 2004 to satisfy energy demand during IPC's peak
periods. Prior to 2004, the IRP calls for IPC to increase
purchases from the Northwest energy markets to meet short-term
energy needs. IPC anticipates that after 2004, transmission
constraints will not allow it to continue to cover increasing
demand by increasing purchases.
IPC issued a request for proposals (RFP), seeking bids for 250 MW
of additional generation to support the growing demand in IPC's
utility service territory. A proposal by Garnet Energy LLC, a
subsidiary of Ida-West Energy, was selected by IPC. In January
2001 IPC signed an agreement with Garnet to define the conditions
under which the utility will purchase energy produced at the 250-
MW project. Garnet has proposed building the natural gas-fired
turbine facility in Canyon County, Idaho, located in the southwest
part of the state.
Upon completion of negotiations, targeted for May 1, 2001, the
contract will be submitted to the IPUC and OPUC for approval and
determination of how purchase power costs will be recovered
through customers' rates.
Regional Transmission Organizations
In December 1999 the Federal Energy Regulatory Commission, in its
landmark Order 2000, said that all companies with transmission
assets must file to form regional transmission organizations
(RTOs) or explain why they cannot. Order 2000 is a follow up to
orders 888 and 889 issued in 1996, which required transmission
owners to provide non-discriminatory transmission service to third
parties. By encouraging the formation of RTOs, FERC seeks to
further facilitate the formation of liquid wholesale electricity
markets.
In response to FERC Order 2000, IPC and other regional
transmission owners filed in October 2000 a plan to form RTO West,
an independent entity that will operate the transmission grid in
eight western states. RTO West will have its own independent
governing board. The participating transmission owners will retain
ownership of the lines, but will not have a role in operating the
grid.
The FERC filing represents a major portion of the filing necessary
to form RTO West. However, substantial additional filings will be
necessary to include the tariff and integration agreements
associated with the new entity and filings for state approvals. We
expect the FERC filings to be completed by the summer of 2001 and
state filings to be initiated in late 2001 or early 2002.
Relicensing of Hydroelectric Projects
We are actively pursuing the relicensing of our hydroelectric
projects, a process that will continue for the next 10 to 15
years. We submitted our first applications for license renewal to
the FERC in December 1995. We have now filed applications seeking
renewal of our licenses for our Bliss, Upper Salmon Falls, Lower
Salmon Falls, CJ Strike and Shoshone Falls Hydroelectric Projects.
Although various federal requirements and issues must be resolved
through the license renewal process, we anticipate that our
efforts will be successful. At this point, however, we cannot
predict what type of environmental or operational requirements we
may face, nor can we estimate the eventual cost of license
renewal. At December 31, 2000, $27 million of relicensing costs
were included in Construction Work in Progress.
Market Risk
The following discussion summarizes the financial instruments,
derivative instruments and derivative commodity instruments
sensitive to changes in interest rates and commodity prices that
we held at December 31, 2000. We buy and sell financial and
physical natural gas and electricity commodity contracts as part
of our ongoing business. These contracts are subject to
electricity and natural gas commodity price risk. We have a
trading and risk management policy defining the limits within
which we contain our commodity price risk. We trade commodity
futures, forwards, options and swaps as a method of managing the
commodity price risk and optimizing the profitability of our
electricity and natural gas trading. We have minimal foreign
exchange exposure related to natural gas trading activities in
Canadian dollars. This exposure is periodically offset through
the use of foreign exchange swap instruments. Our sensitivity
related to foreign exchange rate fluctuations as of December 31,
2000 is immaterial.
Interest Rate Risk Sensitivity
This table presents descriptions of our financial instruments at
December 31, 2000, that are sensitive to changes in interest
rates. We did not hold any interest rate derivative instruments
at December 31, 2000. The majority of our debt is held in fixed
rate securities with embedded call options. We hold $72 million
in variable-rate tax-exempt debt and 11.8 percent of our total
debt is variable in the form of commercial paper. By nature, the
value of our variable rate debt is not sensitive to changes in
interest rates, and the value of our commercial paper borrowings
does not give rise to significant interest rate risk because these
borrowings generally have maturities of less than three months.
The table below presents principal cash flows by maturity date and
the related average interest rate. The table also presents the
fair value for all fixed rate instruments as of December 31, 2000,
based on market rates for similar instruments as of that date.
Expected Average
Maturity Date Amount due interest rate
(in millions)
2001 $ 40 6.9%
2002 37 6.8%
2003 89 6.5%
2004 59 7.9%
2005 69 6.0%
Thereafter 539 7.8%
Total $ 833 7.4%
Fair Value $ 861
Commodity Price Risk Sensitivity
This analysis presents the estimated December 2000, value-at-risk
related to our energy commodity contracts and related derivative
instruments that are sensitive to changes in commodity prices. We
use commodity derivative instruments such as futures, forwards,
options and swaps to manage our exposure to commodity price risk
in the electricity and natural gas markets. The objective of our
risk management program is to mitigate the risk associated with
the purchase and sale of natural gas and electricity. Company
policy also allows the use of these commodity derivative
instruments for trading purposes in support of our operations.
High energy prices and volatility of prices exposes our company to
risk of earnings and cash flow fluctuations. The value-at-risk
measure is a tool used by our Risk Management Committee to
understand the earnings and cashflow risks on a daily basis as the
markets change.
The aggregate potential daily loss in earnings from our energy
trading activity is estimated to be $3.9 million at a 95 percent
confidence interval and for a holding period of one business day.
The potential loss in earnings was estimated using an analytic
value-at-risk methodology. This methodology computes value-at-risk
based upon market prices for futures and historical volatilities
as of December 31, 2000. The value-at-risk is understood to be a
forecast and is not guaranteed to occur. The chosen confidence
level and holding period are industry standards. The confidence
level and holding period imply that there is a five percent chance
that the daily loss will exceed $3.9 million. The value at risk
calculation is principally affected by market prices and
volatility of prices. The extreme increases of volatility and
prices in the energy markets in December 2000 are the primary
cause of the increase in our value at risk. The Risk Management
Committee actively manages the risk to keep our trading activities
within trading limits.
Diversified Business Activities
Telecommunication Services
In August 2000, we formed IDACOMM, Inc. to provide
telecommunications services using fiber optic technology. Also,
in August 2000, we acquired a controlling interest in Rocky
Mountain Communications, Inc. (RMCI), a Boise, Idaho-based
Internet service provider. Since the acquisition, IDACORP and RMCI
launched a new service-Velocitus Broadband. Velocitus offers a
wide variety of broadband solutions for businesses and will be
introduced in 69 markets throughout the western United States.
RMCI currently serves more than 25,000 subscribers of traditional
and high-speed Internet access services in both the residential
and business markets.
As part of the acquisition of RMCI, IDACORP's board of directors
approved the repurchase of up to 350,000 shares of outstanding
common stock. These shares will be distributed to RMCI
shareholders, representing partial payment for the acquisition.
The amount and timing of the repurchase depend on market
conditions. As of December 31, 2000, we had repurchased 156,300
shares for this purpose, at a cost of $6.6 million, and
distributed 154,500 shares to RMCI shareholders. Additional
shares were repurchased in January 2001 and are expected to be
distributed in early 2001.
IDACORP Financial
IDACORP Financial, a wholly owned subsidiary of IDACORP, is
expanding its investment portfolio to include projects that
provide historical tax credits. IDACORP Financial recently closed
on a historical tax credit project in San Diego, California, the
El Cortez project, which began to contribute to earnings in the
third quarter of 2000.
IdaTech
In June 2000, IdaTech (formerly Northwest Power Systems), a
majority-owned subsidiary of IDACORP, delivered the first of 110
fuel cell systems to Bonneville Power Administration (BPA). Since
then, five additional units have been delivered. After three
months of field testing, IdaTech also received notice from the BPA
to proceed with the design and production of the first block of 50
"beta" fuel cell systems for testing in 2001.
IdaTech also received Notice of Allowance from the U.S. Patent
Office of all claims in an additional patent on its fuel
processor. This patent covers the process that will help reduce
the cost of the materials used in the hydrogen purification
module. IdaTech demonstrated a natural gas fuel cell system this
summer and continues to work on key alliances to meet the goal of
commercializing fuel cell systems for home applications by 2003,
and small-scale consumer and commercial applications by late 2002.
Applied Power Company (APC)
In January 2001, we sold APC to Schott Corp. APC is a
manufacturer, supplier and distributor of solar photovoltaic
systems. IDACORP originally acquired APC in 1996.
Environmental and Legal Issues
Salmon Recovery Plan
We are continuing to monitor regional efforts to develop a
comprehensive and scientifically credible plan to ensure the long-
term survival of anadromous fish runs on the Columbia and Lower
Snake rivers.
In mid-August 1994, the federal government changed its designation
of the Fall Chinook Salmon from Threatened to Endangered. This
designation has not had any major effects on our operations.
In September 1991, we voluntarily modified operations at our three-
dam Hells Canyon Complex (HCC) to protect the Fall Chinook
downstream during spawning and juvenile emergence. From its
start, this Fall Chinook Program has provided the Fall Chinook the
high level of protection due an endangered species.
In December 2000, the National Marine Fisheries Service (NMFS)
issued a Final Biological Opinion (BiOp) for operations of the
Federal Columbia River Power System. The BiOp did not call for
changes in the Company's operations for salmon at the HCC.
The NMFS has also developed a draft specifically for operations of
the HCC. The draft BiOp seeks to change existing operations of
the HCC. The NMFS, FERC, and IPC are currently involved in
discussions of the draft BiOp. IPC believes that no changes to
the HCC operations or facilities are justified, and will
vigorously defend this position. However, the Company is unable
to predict what impact, if any, a final NMFS BiOp may have on
operations of the HCC.
The Bureau of Reclamation (BOR) has been seeking, unsuccessfully,
for the last 5 years to acquire additional water in the upper
Snake for fish flow augmentation. While it is likely the BOR will
continue to seek additional water, it is unlikely, absent a
settlement with all Idaho state interests that they will succeed
in their efforts. In connection with water moved in the past, the
Company has been compensated for its losses pursuant to an
agreement with the BPA. If the BOR was successful in its efforts,
the Company would expect compensation.
Threatened and Endangered Snails
In December 1992, the U.S. Fish and Wildlife Service (USFWS)
listed five species of Snake River snails as Threatened and
Endangered Species. Since that time, we have included this
possibility in all of our discussions regarding relicensing and
new hydro development.
The listing specifically mentions the impact that fluctuating
water levels related to hydroelectric operations may have on the
snails and their habitat. Although the hydro facilities on that
reach of the Snake River do not significantly affect water levels
during typical operations, some of them do provide the daily
operational flexibility to meet increased electricity demand
during high load hours. Recent studies suggest that this has no
impact on the listed snails. While it is possible that the
listing could affect how we operate our existing hydroelectric
facilities on the middle reach of the Snake River, we believe that
such changes will be minor and will not present any undue
hardship.
In 1995, as a part of our federal hydro relicensing process, we
obtained a permit from the USFWS to study the five species of
endangered Snake River snails. Our biologists have completed
several studies to gain scientific insight into how or if these
snails are affected by a variety of factors, including hydropower
production, water quality, and irrigation run-off. Results of the
studies indicated that the snail colonies were part of a
biological community well adapted to the influences of hydropower,
water quality, and irrigation run-off. Company-sponsored studies
continue to review how these and other factors affect the status
of the various colonies and their habitats.
Clean Air Act
We have analyzed the Clean Air Act's effects on us and our
customers. Our coal-fired plants in Oregon and Nevada already
meet the federal emission rate standards for sulfur dioxide (SO2)
and our coal-fired plant in Wyoming meets that state's even more
stringent SO2 regulations. Therefore, we foresee no adverse
effects on our operations with regard to SO2 emissions.
New Accounting Pronouncements
In June 1998 the Financial Accounting Standards Board issued
Statement of Financial Accounting Standards No. 133 "Accounting
for Derivative Instruments and Hedging Activities." In June 2000,
the FASB issued SFAS No. 138 "Accounting for Certain Derivative
Instruments and Certain Hedging Activities", which amended certain
provisions of SFAS 133. The Derivative Implementation Group, a
task force created by the FASB, is continuing to identify and
resolve implementation questions related to SFAS 133 and SFAS 138.
SFAS 133, as amended by SFAS 138, was effective as of January 1,
2001. As of January 1, 2001 contracts company-wide have been
evaluated based upon the SFAS 133 derivative definition and
requirements. Most of the Company's identified derivatives
consist of energy trading contracts that are currently reported at
fair value under the provisions of Emerging Issues Task Force 98-
10. The remaining derivatives are IPC electricity purchase and
sales contracts that are subject to regulatory processes. As a
result, the adoption of SFAS 133, as amended, did not have a
material effect on the Company's financial position, results of
operations, or cash flows.
Item 7a. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET
RISK
The information required by this item is included in Item 7
"Management's Discussion and Analysis of Financial Condition and
Results of Operations" under "Market Risk."
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO FINANCIAL STATEMENTS AND FINANCIAL STATEMENT
SCHEDULES
PAGE
Management's Responsibility for Financial Statements 38
Consolidated Financial Statements:
IDACORP, Inc.
Co