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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
X ANNUAL REPORT PURSUANT TO SECTION 13 OR 15 (D) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2001
OR
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from .......to..........
Exact name of Registrant as specified in IRS Employer
Commission its charter, address of principal executive Identification
File Number offices and telephone number Number
1-14465 IDACORP, Inc. 82-0505802
1221 W. Idaho Street
Boise, ID 83702-5627
(208) 388-2200
State or other jurisdiction of incorporation: Idaho
SECURITIES REGISTERED PURSUANT TO SECTION 12(b)
OF THE ACT: Name of
exchange on
which registered
Common Stock, without par value New York and Pacific
Preferred Stock Purchase Rights
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT: None
Indicate by check mark whether the registrant (1) has filed all
reports required to be filed by Section 13 or 15(d) of the
Securities Exchange Act of 1934 during the preceding 12 months (or
for such shorter period that the registrant was required to file
such reports), and (2) has been subject to such filing requirements
for the past 90 days.
Yes ( X ) No ( )
Indicate by check mark if disclosure of delinquent filers pursuant
to Item 405 of Regulation S-K is not contained herein, and will not
be contained, to the best of registrants' knowledge, in definitive
proxy or information statements incorporated by reference in Part
III of this Form 10-K or any amendment to this Form 10-K. ( )
Aggregate market value of voting and non-voting common stock held by
nonaffiliates (February 28, 2002): 1,429,987,610
Number of shares of common stock outstanding at February 28, 2002:
37,590,494
Documents Incorporated by Reference:
Part III, Item 10 - 13 Portions of the joint definitive proxy
statement of the Registrant to be filed pursuant to
Regulation 14A for the 2002 Annual Meeting of
Shareholders to be held on May 16, 2002.
GLOSSARY
AFDC - Allowance for Funds Used During Construction
APB - Accounting Principles Board
APC - Applied Power Company
BPA - Bonneville Power Administration
Cal ISO - California Independent System Operator
CalPX - California Power Exchange
CSPP - Cogeneration and Small Power Production
DIG - Derivatives Implementation Group
DSM - Demand-Side Management
EITF - Emerging Issues Task Force
EPA - Environmental Protection Agency
EPS - Earning per share
FASB - Financial Accounting Standards Board
FERC - Federal Energy Regulatory Commission
FPA - Federal Power Act
Ida-West - Ida-West Energy
IE - IDACORP Energy
IFS - IDACORP Financial Services
IPC - Idaho Power Company
IPUC - Idaho Public Utilities Commission
IRP - Integrated Resource Plan
kW - kilowatt
kWh - kilowatt-hour
LTICP - Long-Term Incentive and Compensation Plan
MD&A - Management's Discussion and Analysis
MMbtu - Million British Thermal Units
MW - Megawatt
MWh - Megawatt-hour
OPUC - Oregon Public Utility Commission
Overton - Overton Power District No. 5
PCA - Power Cost Adjustment
PG&E - Pacific Gas and Electric Company
PUCN - Public Utility Commission of Nevada
PURPA - Public Utilities Regulatory Policy Act
REA - Rural Electrification Administration
RFP - Request for proposals
RMC - Risk Management Committee
RTOs - Regional Transmission Organizations
SCE - Southern California Edison
SFAS - Statement of Financial Accounting Standards
SPPCo - Sierra Pacific Power Company
Valmy - North Valmy Steam Electric Generating Plant
WSCC - Western Systems Coordinating Council
TABLE OF CONTENTS
Page
PART I
ITEM 1. BUSINESS 1
ITEM 2. PROPERTIES 13
ITEM 3. LEGAL PROCEEDINGS 15
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS 15
EXECUTIVE OFFICERS OF THE REGISTRANTS 16
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON STOCK AND RELATED
STOCKHOLDER MATTERS 17
ITEM 6. SELECTED FINANCIAL DATA 17
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS 18
ITEM 7A.QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT
MARKET RISK 39
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA 40
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE 72
PART III
ITEM 10.DIRECTORS AND EXECUTIVE OFFICERS OF THE
REGISTRANTS* 72
ITEM 11.EXECUTIVE COMPENSATION* 72
ITEM 12.SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT* 72
ITEM 13.CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS* 72
PART IV
ITEM 14.EXHIBITS, FINANCIAL STATEMENT SCHEDULE AND REPORTS
ON FORM 8-K 72
SIGNATURES 75
*INCORPORATED BY REFERENCE.
SAFE HARBOR STATEMENT
This Form 10-K contains "forward-looking statements" intended to
qualify for safe harbor from liability established by the Private
Securities Litigation Reform Act of 1995. Forward-looking
statements should be read with the cautionary statements and
important factors included in this Form 10-K at Part II, Item 7-
"Management's Discussion and Analysis of Financial Condition and
Results of Operations - Forward-Looking Information." Forward-
looking statements are all statements other than statements of
historical fact, including without limitation those that are
identified by the use of the words "anticipates," "estimates,"
"expects," "intends," "plans," "predicts," and similar
expressions.
PART I
ITEM 1. BUSINESS
OVERVIEW
IDACORP, Inc. (IDACORP or the Company) is a holding company
incorporated in 1998 under the laws of the state of Idaho and is the
parent of Idaho Power Company (IPC), IDACORP Energy (IE), and
several other entities. IPC is an electric utility regulated by the
Federal Energy Regulatory Commission (FERC) and the state regulatory
commissions of Idaho, Oregon, Nevada and Wyoming, and is engaged in
the generation, transmission, distribution, sale and purchase of
electric energy. IPC is the parent of Idaho Energy Resources Co., a
joint venturer in Bridger Coal Company, which supplies coal to IPC's
Jim Bridger generating plant. IE markets electricity and natural
gas, and offers risk management and asset optimization services, to
wholesale customers in 31 states and two Canadian provinces.
IDACORP's other subsidiaries are:
Ida-West Energy (Ida-West) - independent power projects
development and management;
IdaTech - developer of integrated fuel cell systems;
IDACORP Financial Services (IFS) - affordable housing and
other real estate investments;
Velocitus - commercial and residential Internet service
provider;
IDACOMM - provider of telecommunications services.
IPC transferred its non-utility wholesale electricity marketing
operations to IE effective June 11, 2001.
At December 31, 2001, the Company had 1,999 full-time employees.
Of these employees, 1,688 are employed by IPC.
The Company has identified two reportable business segments, the
regulated utility operations of IPC, and the energy marketing
activities of IE. IPC and IE contributed 16 percent and 84
percent to consolidated operating revenues, respectively, during
the year ended December 31, 2001. We present additional
information about our operating segments in Note 12 to the
Consolidated Financial Statements and below in "Utility
Operations" and "Energy Marketing."
UTILITY OPERATIONS
IPC was incorporated under the laws of the state of Idaho in 1989
as successor to a Maine corporation organized in 1915. IPC is
involved in the generation, purchase, transmission, distribution
and sale of electric energy in a 20,000 square mile area in
southern Idaho and eastern Oregon, with an estimated population
of 873,000. IPC holds franchises in 72 cities in Idaho and ten
cities in Oregon and holds certificates from the respective public
utility regulatory authorities to serve all or a portion of 28
counties in Idaho and three counties in Oregon. As of December
31, 2001, IPC supplied electric energy to over 401,000 general
business customers.
IPC owns and operates 17 hydroelectric power plants, one
natural gas-fired plant and shares ownership in three coal-fired
generating plants. These generating plants and their capacities
are listed in Item 2. "Properties." IPC's coal-fired plants are
in Wyoming, Oregon and Nevada, and use low-sulfur coal from
Wyoming and Utah.
IPC relies heavily on hydroelectric power for its generating needs
and is one of the nation's few investor-owned utilities with a
predominantly hydroelectric generating base. Because of its
reliance on hydro generation, IPC's generation operations can be
significantly affected by the weather. The availability of
inexpensive hydroelectric power depends on snowpack in the
mountains above IPC's hydro facilities, precipitation and other
weather and streamflow management considerations. When
hydroelectric generation decreases and customer demand increases,
IPC increases its use of more expensive thermal generation and
purchased power.
The rates IPC charges to its general business customers are
determined by the various regulatory authorities. Approximately
95 percent of IPC's general business revenue and sales come from
customers in Idaho. The rates charged to these customers are
adjusted annually by a power cost adjustment (PCA) mechanism. The
PCA adjusts rates to reflect the changes in costs incurred by IPC
to supply power. Throughout the year, IPC compares its actual
power supply costs to the amounts it is recovering in rates.
Most, but not all, of this difference is deferred and included in
the calculation of rates for future years. The PCA is discussed
in more detail below in "Rates" and in Note 13 to the Consolidated
Financial Statements.
The primary influences on electricity sales are weather and
economic conditions. Generally, extreme temperatures increase
sales to customers, who use electricity for cooling and heating,
and moderate temperatures decrease sales. Precipitation levels
during the growing season affect sales to customers who use
electricity to operate irrigation pumps. Increased precipitation
reduces electricity usage by these customers.
IPC's principal commercial and industrial customers are involved
in: food processing, electronics and general manufacturing,
lumber, beet sugar refining, and the skiing industry.
Regulation
IPC is under the regulatory jurisdiction (as to rates, service,
accounting and other general matters of utility operation) of the
FERC, the Idaho Public Utilities Commission (IPUC), the Oregon
Public Utility Commission (OPUC) and the Public Utility Commission
of Nevada (PUCN). IPC is also under the regulatory jurisdiction
of the IPUC, OPUC and the Public Service Commission of Wyoming as
to the issuance of securities. IPC is subject to the provisions
of the Federal Power Act (FPA) as a "licensee" and "public
utility" as therein defined. IPC's retail rates are established
under the jurisdiction of the state regulatory agencies and its
wholesale and transmission rates are regulated by the FERC (see
"Rates"). Pursuant to the requirements of Section 210 of the
Public Utilities Regulatory Policy Act of 1978 (PURPA), the state
regulatory agencies have each issued orders and rules regulating
IPC's purchase of power from Cogeneration and Small Power
Production (CSPP) facilities.
As a licensee under the FPA, IPC and its licensed hydroelectric
projects are subject to the provisions of Part I of the Act. All
licenses are subject to conditions set forth in the FPA and
related FERC regulations. These conditions and regulations
include provisions relating to condemnation of a project upon
payment of just compensation, amortization of project investment
from excess project earnings, possible takeover of a project after
expiration of its license upon payment of net investment,
severance damages, and other matters.
The state of Oregon has a Hydroelectric Act providing for
licensing of hydroelectric projects in that state. IPC's
Brownlee, Oxbow and Hells Canyon facilities are on the Snake River
where it forms the boundary between Idaho and Oregon and occupy
land located in both states. With respect to project property
located in Oregon, these facilities are subject to the Oregon
Hydroelectric Act. IPC has obtained Oregon licenses for these
facilities and these licenses are not in conflict with the FPA or
IPC's FERC license (see Item 2. "Properties").
Rates
Idaho Jurisdiction: IPC has a PCA mechanism that provides for
annual adjustments to the rates charged to its Idaho retail electric
customers. These adjustments, which take effect annually in May,
are based on forecasts of net power supply expenses and the true-up
of the prior year's forecast. During the year, the difference
between the actual costs incurred and the forecasted costs is
deferred, with interest. The balance of this deferral, called a
true-up, is then included in the calculation of the next year's PCA
adjustment.
So far in the 2001-2002 rate year actual power supply costs included
in the PCA have been significantly greater than forecast due to
purchased power volumes and prices being greater than originally
forecasted and the implementation of the voluntary load reduction
payments with Astaris and the irrigation customers. To account for
these higher-than-forecasted costs, and the unamortized portion of
the 2000-2001 PCA balance, IPC has recorded regulatory assets of
$290 million as of December 31, 2001.
In the 2001 PCA filing, IPC requested recovery of $227 million of
power supply costs. In May, the IPUC authorized recovery of $168
million, but deferred recovery of $59 million pending further
review. The approved amount resulted in an average rate increase of
31.6 percent. After conducting hearings on the remaining $59
million, the IPUC authorized recovery of $48 million plus $1 million
of accrued interest, beginning in October 2001. The remaining $11
million not recovered in rates from the PCA filing was written off
in September 2001.
Other Jurisdictions: IPC filed an application with the OPUC to
begin recovering extraordinary 2001 power supply costs in its
Oregon jurisdiction. On June 18, 2001, the OPUC approved new
rates that would recover $1 million over the next year. Under the
provisions of the deferred accounting statute, annual rate
recovery amounts were limited to three percent of IPC's 2000 gross
revenues in Oregon. During the 2001 session, the Oregon
Legislature amended the statute giving the OPUC authority to
increase the maximum annual rate of recovery of deferred amounts
to six percent for electric utilities. IPC subsequently filed on
October 5, 2001 to recover an additional three percent
extraordinary deferred power supply costs. As a result of this
filing, the OPUC issued Order No. 01-994 allowing IPC to increase
its rate of recovery to six percent effective November 28, 2001.
The Oregon deferral balance is $15 million as of December 31,
2001, net of the June 18, 2001 and November 28, 2001 recovery.
Power Supply
IPC meets its system load requirements using a combination of its
own system generation, mandated purchases from private developers
(see "CSPP Purchases" below), and purchases from other utilities
and power wholesalers. IPC's generating stations and capacities
are listed in "Item 2. Properties."
IPC's system is dual peaking, with the larger peak demand
generally occurring in the summer. The system peak demand for
2001 was 2,570 MW, set on July 2, 2001. Peak demands in 2000 and
1999 were 2,919 MW and 2,839 MW, respectively. IPC expects total
system energy requirements to grow 2.2 percent annually over the
next three years.
The amounts of electricity IPC is able to generate from its hydro
plants depend on a number of factors, primarily snowpack in the
mountains above its hydro facilities, reservoir storage, and
streamflow requirements. When these factors are favorable, IPC can
generate more electricity using its hydroelectric plants. When these
factors are unfavorable, IPC must increase its reliance on more
expensive thermal plants and purchased power.
Below normal water conditions in 2001 yielded a system generation mix
of 43 percent hydro and 57 percent thermal. Historically, under
normal water conditions, IPC's system generation mix is approximately
57 percent hydro and 43 percent thermal.
The Snake River Basin snowpack numbers offer the promise of
improved streamflows for 2002. IPC's mid-February 2002
accumulations were 84 percent of normal, compared to 51 percent at
the same time a year earlier. Even though snowpack is closer to
normal, reservoir storage is not, meaning hydro conditions will
not fully return to normal in 2002.
In September 2001, IPC placed in service Danskin Power Plant, a 90-
MW natural gas-fired combustion turbine plant, located near
Mountain Home, Idaho.
Seasonal exchanges of winter-for-summer power are included among
the contracted resources to maximize the firm load carrying
capability. Exchanges are currently made with NorthWestern
Energy under a contract that expires December 2003 and with
Seattle City Light under a contract that expires October 2002.
IPC's generating facilities are interconnected through its
integrated transmission system and are operated on a coordinated
basis to achieve maximum load-carrying capability and reliability.
IPC's transmission system is directly interconnected with the
transmission systems of the Bonneville Power Administration (BPA),
Avista Corporation, PacifiCorp, NorthWestern Energy and
Sierra Pacific Power Company (SPPCo). Such interconnections,
coupled with transmission line capacity made available under
agreements with certain of the above utilities, permit the
interchange, purchase and sale of power among all major electric
systems in the West. IPC is a member of the Western Systems
Coordinating Council (WSCC), the Western Systems Power Pool, the
Northwest Power Pool, the Western Regional Transmission
Association and the Northwest Regional Transmission Association.
These groups are being formed to more efficiently coordinate
transmission reliability and planning throughout the western grid.
See "Competition - Wholesale" discussion below.
Integrated Resource Plan (IRP): Every two years, IPC is required
to file with the IPUC and OPUC an IRP, a comprehensive look at
IPC's present and future demands for electricity and plans for
meeting that demand. The 2000 IRP identified a potential
electricity shortfall within our utility service territory by mid-
2004. The plan projected a 250-MW resource need in 2004 to
satisfy energy demand during IPC's peak periods. The IRP calls
for IPC to use purchases from the Northwest energy markets to meet
short-term energy needs. The 2000 IRP anticipates that after
2004, transmission constraints will not allow IPC to cover
increasing demand using wholesale purchases from the Pacific
Northwest.
As a result of the 2000 IRP, IPC issued a request for proposals
(RFP), seeking bids for 250-MWs of additional generation to support
the growing demand in IPC's utility service territory. A proposal
by Garnet Energy LLC, a subsidiary of Ida-West, was selected by
IPC. In December 2001 IPC signed an agreement with Garnet to
define the conditions under which the utility will purchase energy
to be produced by Garnet's proposed 273-MW natural gas-fired,
combined cycle combustion turbine facility in Canyon County, Idaho,
located in the southwest part of the state. In December 2001, IPC
filed an application with the IPUC requesting authorization to
include Garnet related expenses in the Company's PCA. On February
27, 2002, the IPUC tentatively set hearings in June 2002 to hear
Idaho Power's request.
CSPP Purchases: As a result of the enactment of the PURPA and the
adoption of avoided cost standards by the IPUC, IPC has entered into
contracts for the purchase of energy from private developers.
Because IPC's service territory encompasses substantial irrigation
canal development, forest product production facilities, mountain
streams, and food processing facilities, considerable amounts of
energy are available from these sources. Such energy comes from
hydropower producers who own and operate small plants and from
cogenerators converting waste heat or steam from industrial
processes into electricity. The total cost of power purchased from
CSPP projects was $45 million in 2001. During 2001, IPC purchased
728,155 MWh from these private developers at a blended price of
6.2 cents per kWh.
The IPUC has determined that negotiated rates for future CSPP
projects larger than one MW should be tied more closely to values
determined in IPC's integrated resource planning process and has
limited the length of new contracts to a maximum of five years.
Wholesale Power Sales: IPC has firm wholesale power sales contracts
with five entities. These contracts are for various amounts of
energy, up to 36 average megawatts, and are of various lengths
expiring between 2002 and 2009.
Transmission Services: IPC has a long history of providing wholesale
transmission service and provides various firm and non-firm wheeling
services for several surrounding utilities. IPC's system lies
between and is interconnected to the winter-peaking northern and
summer-peaking southern regions of the western interconnected power
system. This position allows IPC to provide transmission services
and reach a broad power sales market.
In December 1999, the FERC issued Order No. 2000 encouraging
companies with transmission assets to form Regional Transmission
Organizations (RTOs). See further discussion in "Competition -
Wholesale."
Fuel
IPC, through its subsidiary Idaho Energy Resources Co., owns a one-
third interest in the Bridger Coal Company, which owns the Jim
Bridger mine supplying coal to the Jim Bridger generating plant in
Wyoming. The mine, located near the Jim Bridger plant, operates
under a long-term sales agreement that provides for delivery of
coal over a 51-year period ending in 2025. The Jim Bridger mine
has sufficient reserves to provide coal deliveries pursuant to the
sales agreement. IPC also has a coal supply contract providing
for annual deliveries of coal through 2005 from the Black Butte
Coal Company's Black Butte and Leucite Hills mines located near
the Jim Bridger project. This contract supplements the Bridger
Coal Company deliveries and provides another coal supply to
operate the Jim Bridger plant. The Jim Bridger plant's rail load-
in facility and unit coal train allows the plant to take advantage
of potentially lower-cost coal from outside mines for tonnage
requirements above established contract minimums.
SPPCo, with whom IPC is a joint (50/50) participant in the
ownership and operation of the North Valmy Steam Electric
Generating plant (Valmy), has a long-term coal contract with
Southern Utah Fuel Company, a subsidiary of Canyon Fuel Co., LLC.
This contract, which expires on June 30, 2003, calls for the
delivery of up to 17.5 million tons of low-sulfur coal from a mine
near Salina, Utah, for Valmy Unit No. 1.
In 1986, IPC and SPPCo signed a long-term coal supply agreement with
the Black Butte Coal Company. Black Butte is expected to
discontinue delivery to the Valmy project as IPC has fulfilled its
purchase obligation specified in the coal supply agreement. This
agreement had provided for Black Butte to supply coal to the Valmy
project under a flexible delivery schedule that allowed for
variations in the number of tons to be delivered ranging from a
minimum of 300,000 tons per year to a maximum of one million tons
per year.
SPPCO is currently negotiating a coal sales agreement with Arch
Coal Sales Company, Inc. to supply coal to the Valmy project from
2002 through 2006. IPC would be obligated to purchase one-half of
the coal, ranging from approximately 515,000 tons to 762,500 tons
annually, under this agreement.
Water Rights
Except as discussed below, IPC has acquired valid water rights
under applicable state law for all waters used in its
hydroelectric generating facilities. In addition, IPC holds water
rights for domestic, irrigation, commercial and other necessary
purposes related to other land and facility holdings within the
state. The exercise and use of all of these water rights are
subject to prior rights and, with respect to certain hydroelectric
facilities, IPC's water rights for power generation are
subordinated to future upstream diversions of water for irrigation
and other recognized consumptive uses.
Over time, increased irrigation development and other consumptive
diversions have resulted in some reduction in the stream flows
available to fulfill IPC's water rights at certain hydroelectric
generating facilities. In reaction to these reductions, IPC
initiated and continues to pursue a course of action to determine
and protect its water rights. As part of this process, IPC and
the state of Idaho signed the Swan Falls agreement on October 25,
1984 which provided a level of protection for IPC's hydropower
water rights at specified plants by setting minimum stream flows
and establishing an administrative process governing the future
development of water rights that may affect IPC's hydroelectric
generation. In 1987, Congress passed and the President signed
into law House Bill 519. This legislation permitted
implementation of the Swan Falls agreement and further provided
that during the remaining term of certain of IPC's project
licenses that the relationship established by the agreement would
not be considered by the FERC as being inconsistent with the terms
of IPC's project licenses or imprudent for the purposes of
determining rates under Section 205 of the FPA. The FERC entered
an order implementing the legislation on March 25, 1988.
In addition to providing for the protection of IPC's hydropower
water rights, the Swan Falls agreement contemplated the initiation
of a general adjudication of all water uses within the Snake River
basin. In 1987, the director of the Idaho Department of Water
Resources filed a petition in state district court asking that the
court adjudicate all claims to water rights, whether based on
state or federal law, within the Snake River basin. A
commencement order initiating the Snake River Basin Adjudication
was signed by the court on November 19, 1987. This legal
proceeding was authorized by state statute based upon a
determination by the Idaho Legislature that the effective
management of the waters of the Snake River basin required a
comprehensive determination of the nature, extent and priority of
all water uses within the basin. The adjudication is proceeding
and is expected to continue for at least the next 10 years. IPC
has filed claims to its water rights within the basin and is
actively participating in the adjudication to ensure that its
water rights and the operation of its hydroelectric facilities are
not adversely impacted. IPC does not anticipate any modification
of its water rights as a result of the adjudication process.
Environmental Regulation
Environmental regulation at the federal, state, regional and local
levels is having a continuing impact on IPC's operations due to
the cost of installation and operation of equipment and facilities
required for compliance with such regulations and the modification
of system operations to accommodate such regulation.
Based upon present environmental laws and regulations, IPC estimates
its 2002 capital expenditures for environmental matters, excluding
allowance for funds used during construction (AFDC), will total $14
million. Studies and measures related to mitigation of environmental
concerns due to relicensing of hydro facilities account for $10
million and investments in environmental equipment and facilities at
the thermal plants account for $4 million. During the 2003-2004
period, environmental-related capital expenditures are estimated to
be $31 million. IPC anticipates $23 million in annual operating
costs for environmental facilities during the 2002-2004 period.
Clean Air: IPC has analyzed the Clean Air Act legislation and its
effects upon IPC and its customers. IPC's coal-fired plants in
Oregon and Nevada already meet the federal emission rate standards
for sulfur dioxide (SO2) and IPC's coal-fired plant in Wyoming meets
that state's even more stringent SO2 regulations. IPC has sufficient
SO2 allowances to provide compliance for all three coal-fired
facilities and its Danskin natural gas-fired facility. Therefore,
IPC does not foresee any material adverse effects upon its operations
with regard to SO2 emissions.
In July 1997, the Environmental Protection Agency (EPA) announced new
National Ambient Air Quality Standards for ozone and Particulate
Matter (PM) and in July 1999 the EPA announced regional haze
regulations for protection of visibility in national parks and
wilderness areas. On May 14, 1999, a federal court ruling blocked
implementation of these standards, which EPA proposed in 1997. In
November 2000, the EPA appealed to the U.S. Supreme Court to
reconsider that decision. No ruling has been made by the court as of
December 31, 2001. Impacts of the ozone and PM regulations and
regional haze regulations on IPC's thermal operations are unknown at
this time.
Valmy, Boardman and Jim Bridger Unit 4 elected to meet Phase I
nitrogen oxide (NOx ) limits beginning in 1998. As a result of
this voluntary "early election" these units will not be required
to meet the more restrictive Phase II NO x limits until 2008. Had
the units not voluntarily "early elected," they would have been
required to meet the Phase II limits in 2000. Jim Bridger Units
1, 2, and 3 were accepted as substitution units in 1995 and are
subject to NO x limits of Phase I instead of the more restrictive
limits of Phase II. Jim Bridger has installed low NO x equipment
to reduce NO x levels even lower than currently required.
The Danskin gas turbine plant in Mountain Home is operating in
compliance with a "permit to construct" issued by the Idaho
Department of Environmental Quality. The units are fitted with dry-
low- NO x burners and a continuous emissions monitoring system.
This should ensure that the facility will operate within the permitted
federal and state NO x and carbon monoxide limits.
Water: IPC has received National Pollutant Discharge Elimination
System Permits, as required under the Federal Water Pollution
Control Act Amendments of 1972, for the discharge of effluents from
its hydroelectric generating plants.
IPC has agreed to meet certain dissolved oxygen standards at its
American Falls hydroelectric generating plant. IPC signed
amendments to the agreements relating to the operation of the
American Falls Dam and the location of water quality monitoring
facilities. The amendments were made to provide more accurate and
reliable water quality measurements necessary to maintain water
quality standards downstream from IPC's plant during the period
from May 15 to October 15 each year.
IPC has installed aeration equipment, water quality monitors and
data processing equipment as part of the Cascade hydroelectric
project to provide accurate water quality data and increase
dissolved oxygen levels as necessary to maintain water quality
standards on the Payette River. IPC has also installed and
operates water quality monitors at the Milner, Shoshone Falls,
Twin Falls, Upper Salmon, Lower Salmon and Bliss hydroelectric
projects, in order to meet compliance standards for water quality.
IPC owns and finances the operation of anadromous fish hatcheries and
related facilities to mitigate the effects of its hydroelectric dams
on fish populations. In connection with its fish facilities, IPC
sponsors ongoing programs for the control of fish disease and
improvement of fish production. IPC's anadromous fish facilities at
Hells Canyon, Oxbow, Rapid River, Pahsimeroi and Niagara Springs
continue to be operated by the Idaho Department of Fish and Game. At
December 31, 2001, the investment in these facilities was $10 million
and the annual cost of operation pursuant to FERC License 1971 is
approximately $2 million.
Endangered Species: Several species of fish and Snake River snails
living within IPC's operating area are listed as threatened or
endangered. IPC continues to review and analyze the effect such
designation has on its operations. IPC is cooperating with various
governmental agencies to resolve issues related to these species.
See Part II, Item 7. "Management's Discussion and Analysis of
Financial Condition and Results of Operations - Environmental and
Legal Issues."
Hazardous/Toxic Wastes and Substances: Under the Toxic Substances
Control Act (TSCA), the EPA has adopted regulations governing the
use, storage, inspection and disposal of electrical equipment that
contain polychlorinated biphenyls (PCBs). The regulations permit the
continued use and servicing of certain electrical equipment
(including transformers and capacitors) that contain PCBs. IPC
continues to meet all federal requirements of TSCA for the continued
use of equipment containing PCBs. This program will save costs
associated with the long-term monitoring and testing of equipment and
grounds for PCB contamination as well as being good for the
environment. Total IPC costs for the identification and disposal of
PCBs from IPC's system were less than $1 million each year from 1999
to 2001. IPC believes that all generation facilities are presently
non-PCB.
Competition
Retail: Electric utilities have historically been recognized as
natural monopolies and have operated in a highly regulated
environment in which they have an obligation to provide electric
service to their customers in return for an exclusive franchise
within their service territory with an opportunity to earn a
regulated rate of return.
Some state regulatory authorities are in the process of changing
utility regulations in response to federal and state statutory
changes and evolving competitive markets. These statutory changes
and conforming regulations may result in increased retail
competition. In 1997, the Idaho Legislature appointed a committee
to study restructuring of the electric utility industry. Although
the committee will continue studying a variety of restructuring
ideas, it has not recommended any restructuring legislation and is
not expected to in the foreseeable future. In 1999, the Oregon
legislature passed legislation restructuring the electric utility
industry,but exempted IPC's service territory.
Wholesale: The 1992 Energy Act (Energy Act) and the FERC's
rulemaking activities have established the regulatory framework to
open the wholesale energy market to competition. The Energy Act
permits utilities to develop independent electric generating
plants for sales to wholesale customers, and authorizes the FERC
to order transmission access for third parties to transmission
facilities owned by another entity. The Energy Act does not,
however, permit the FERC to require transmission access to retail
customers. Open-access transmission for wholesale customers
provides energy suppliers with opportunities to sell and deliver
electricity at market-based prices.
In December 1999 the FERC, in its landmark Order 2000, said that all
companies with transmission assets must file to form RTOs or explain
why they cannot. Order 2000 is a follow up to Orders No. 888 and
889 issued in 1996, which required transmission owners to provide
non-discriminatory transmission service to third parties. By
encouraging the formation of RTOs, the FERC seeks to further
facilitate the formation of efficient, competitive wholesale
electricity markets.
In response to FERC Order 2000, IPC and other regional transmission
owners filed, in October 2000, a plan to form RTO West, an entity
that will operate the transmission grid in seven western states.
RTO West will have its own independent governing board. The
participating transmission owners will retain ownership of the
lines, but will not have a role in operating the grid.
This FERC filing represents a portion of the filing necessary to
form RTO West. However, substantial additional filings will be
necessary to include the tariff and integration agreements
associated with the new entity. There will also need to be filings
for state approvals. IPC expects the "Stage 2" FERC filing to be
completed by March 2002. State filings may be initiated in late
2002.
Utility Operating Statistics
The following table presents IPC's revenues and volumes for the last
three years:
Years Ended December 31,
2001 2000 1999
Revenues (millions of dollars)
Residential $ 260 225 214
Commercial 164 132 123
Industrial 154 133 117
Irrigation 72 75 62
Total general business 650 565 516
Off system sales 220 230 120
Other 44 42 24
Total $ 914 837 660
Energy use (thousands of MWhs)
Residential 4,307 4,393 4,200
Commercial 3,380 3,404 3,194
Industrial 3,925 4,808 4,666
Irrigation 1,419 1,993 1,706
Total general business 13,031 14,598 13,766
Off system sales 2,387 4,529 5,924
Total 15,418 19,127 19,690
ENERGY MARKETING
In January 1997, IPC began implementing a strategy to become a
competitive energy provider throughout the western markets. In
order to compete as an energy provider of choice, IPC built a
trading operation to participate in the electricity, natural gas
and other related markets. In 1997 IPC developed natural gas
trading operations which were transferred to IE in 1999.
Effective June 11, 2001, IPC transferred its non-utility
wholesale electricity marketing operations ("Energy Marketing")
to IE.
IE has offices in Boise, Idaho and Houston, Texas and employed
approximately 120 people at December 31, 2001. IE's energy marketing
strategy has produced increasingly positive results through growing
the volume of energy delivered, expanding the geographic area in
which IE does business, and capitalizing on the recent high
volatility of energy prices. While IE continues to be active
in the natural gas markets, its business expansion has primarily
been driven from three interdependent strategies in the electricity
markets. First, IE uses its expertise in the physical power
system within the western United States to purchase the rights
to strategic transmission. While IE has no obligation to renew
these rights annually, many of them can be extended indefinitely,
barring any regulatory changes, giving it the ability to assess
the value of the rights on an annual basis before renewal.
The second piece of its strategy is to buy and sell energy
around these contractual transmission assets and take advantage
of market price movements between regions while limiting its
market risk. Third, IE uses its knowledge of the physical
system coupled with its risk management expertise to create
customized, or structured, energy solutions for end-use customers.
Additionally, IE offers asset management services to utilities and
other regulated energy providers. One such agreement is with the
Company's affiliate, IPC. Concurrent with the June 2001 transfer of
the non-utility electricity marketing business from IPC to IE, IE
and IPC entered into an Electricity Supply Management Services
Agreement (Agreement). IPC received approval of the Agreement from
the IPUC, OPUC and the FERC. Under the Agreement, IPC will continue
to own, operate and maintain its electric generating equipment and
transmission facilities (system resources) and be responsible for
system reliability. IE will manage and dispatch the system resources
to balance generation and load within the IPC operating area.
Revenues for the energy marketing segment, including intersegment
revenues, for 2001, 2000 and 1999 were $4,893 million, $2,462 million
and $872 million respectively. The growth in revenue was due to
an increase in wholesale electricity prices and growth in settled
physical electricity volume from 14.4 million MWh's in 1999 to 23.5
million MWh's in 2000 and 34.9 million MWh's in 2001.
Risk Management: When buying and selling energy, the high
volatility of energy prices can have significant negative impact on
profitability if not appropriately managed. Also, counterparty
creditworthiness is key to ensuring that transactions entered into
can withstand potentially dramatic market fluctuations. To manage
the risks inherent in the energy commodity industry while
implementing the Company's business strategy, the Risk Management
Committee (RMC), comprised of Company officers, oversees the
Company's risk management program as defined in the risk management
policy. The program is intended to manage the impact to earnings
caused by the volatility of energy prices by mitigating commodity
price risk, credit risk, and other risks related to the energy
commodity business.
To manage the risks inherent in its portfolio, the Company has
established risk limits. Market and credit risk is measured and
reported daily to the members of the RMC. Other tools used to
manage credit risk are the holding of collateral in the form of cash
or letters of credit and the use of margining agreements with
counterparties when credit risk exceeds certain pre-determined
thresholds. Because of the volatile nature of energy market prices,
margining agreements can require the posting of large amounts of
cash between counterparties to hold as collateral against the value
of the energy contracts. This practice mitigates credit risk but
increases the need for cash or other liquid securities to ensure the
ability to meet all margin requirements when the markets are most
volatile.
At year-end 2001, 69 percent of the credit exposure related to IE's
unrealized positions is with investment grade counterparties. Less
than 0.5 percent is with non-investment grade counterparties. The
remaining 31 percent of year-end credit exposure is with non-rated
counterparties. The majority of the non-rated entities are
municipalities, public utility districts and electric cooperatives.
See further discussion in Part II Item 7 "Management's Discussion
and Analysis - Market Risk."
Supply: IE's supply of electricity and natural gas is purchased
directly from producers as well as other energy marketers. Sales of
energy are made to other marketers, investor owned utilities,
municipalities and cooperatives as well as large commercial and
industrial customers in regions that allow retail customer choice.
Approximately 55 percent of the marketing and trading business in
2001 was with other marketing companies.
Competition: Competition in energy marketing and trading
continues to increase. There are over 150 counterparties active
in the energy markets in the WSCC and all are increasing in their
sophistication. IE anticipates that lower prices and decreased
volatility may negatively impact its business. While IE is not
dependent on market prices for income, its profitability does
depend upon volume and spread. Both bid/ask spread and regional
pricing spreads are typically much lower during periods of lower
prices. Further, deteriorating credit conditions of our counter
parties are limiting IE's ability to transact with those counter
parties, decreasing the rate of growth of transaction volume.
While disciplined adherence to IE's policy toward credit may
limit short term profitability, IE believes it is prudent to do
so in order to manage risks properly and sustain the quality of
earnings in the long run.
Energy Marketing Operating Statistics
The following table presents IE's revenues and volumes (including
intersegment transactions) for the last three years:
Years Ended December 31,
2001 2000 1999
Revenues (Millions of dollars)
Electricity $ 4,531 $ 2,191 $ 594
Gas 362 271 278
Total $ 4,893 $ 2,462 $ 872
Operating Volumes (Settled)
Electricity (MWhs) 34,936,951 23,518,454 14,433,650
Gas (mmbtu's) 97,327,432 80,728,530 141,432,755
IDA-WEST
Ida-West develops, acquires, constructs, finances, owns and operates
electric power generation facilities. Ida-West has a 50 percent
interest in nine operating hydroelectric plants with a total
generating capacity of 45 MW.
Ida-West is developing the 273-MW Garnet Energy Facility, which will
begin operation as soon as 2004, in Canyon County, Idaho. This
facility will provide up to 250 MW for IPC's future peak energy
needs. The project is the result of a competitive bidding process
conducted by IPC, which has indicated it will face an electric
energy shortfall during certain months beginning as soon as the
summer of 2004. Garnet, a combined-cycle combustion turbine
project, is capable of expansion to 540 MW.
In 2001 the Friant Power Authority redeemed bonds that represented
Ida-West's investment in the Friant Power Project, a 27.4 MW project
located in California. The Friant bonds were originally acquired in
1996. Ida-West recorded a pre-tax gain of $5 million on this
transaction in 2001.
In 2000, Ida-West sold its interest in the Hermiston Power project,
a 536-MW gas-fired project currently under construction near
Hermiston, Oregon. Ida-West was responsible for managing all
permitting and development activities relating to the project since
its inception in 1993. Ida-West recorded a pre-tax gain of $14
million on this transaction in 2000.
IPC has purchased all of the power generated by Ida-
West's four Idaho hydroelectric projects, at a cost of $6 million in
2001.
IDATECH
IdaTech was organized in 1996 as Northwest Power Systems, LLC
with the intent to bring fuel cell technology to market. In
April 1999 IDACORP purchased a majority interest in IdaTech.
IdaTech is a developer of fuel processors and proton-exchange-
membrane fuel cell systems. These fuel cell systems are designed
with various outputs for stationary and portable electric power generation.
With six patents issued and more than 50 pending, IdaTech's development
efforts are focused on the commercialization of a methanol fuel processor,
which is capable of producing a very high level of pure hydrogen.
Additionally, the company is strengthening its ability to reform other
conventional fuels including natural gas, propane, and kerosene.
In 2001 IdaTech began the design, production and delivery of the first
beta fuel cell systems for testing in 2001 and 2002, as agreed upon in
a contract with the Bonneville Power Administration. IdaTech is also
field-testing its fuel cell systems in Japan in cooperation with Tokyo
Boeki, Ltd., and in Europe in cooperation with Electricite De France (EDF).
IdaTech anticipates commercialization of its methanol fuel processor
module in 2002, and also plans to continue field-testing its portable
fuel cell system.
IDACOMM and Velocitus
In August 2000, we formed IDACOMM, Inc. and acquired Velocitus, Inc.
(formerly Rocky Mountain Communications, Inc.), a Boise, Idaho-based
Internet service provider founded in 1992. IDACOMM and Velocitus
provide a wide range of integrated communication services to
business and residential customers in several western states,
Virginia and New York.
IDACOMM, an integrated communication provider, delivers high-speed
connectivity, using fiber optic network technology. IDACOMM's
technologies enable high-speed voice, Internet and data communications,
including video conferencing, voice-over IP, off-site training and gigabit
Ethernet service. IDACOMM's customers include Fortune 500 companies as
well as government entities and school districts. IDACOMM's Metropolitan
Area Network in Idaho's Treasure Valley serves Boise, Meridian, Nampa and
Caldwell.
Velocitus operates as a Managed Service Provider by offering high-
speed Internet access, Internet system support and other related
services such as Virtual Private Networks, Firewalls and Web Hosting
to more than 25,000 customers. Velocitus Internet serves the
traditional residential and general consumer segment. Velocitus
Broadband targets small to medium size business clients with high-
speed connectivity and security solutions, including fixed wireless
technology, allowing for rapid deployment and prompt service
installation. Velocitus Broadband is currently available to
customers in parts of Idaho, Washington, Oregon, California, New
Mexico, Arizona and Utah with additional western markets opening in
2002.
IDACORP FINANCIAL SERVICES
IFS invests primarily in affordable housing projects, which
provide a return primarily by reducing federal income taxes
through tax credits and tax depreciation benefits. In 2000, IFS
expanded its portfolio to include historic rehabilitation projects
such as the El Cortez Hotel in San Diego, California and the
Empire Building in Boise, Idaho.
RESEARCH AND DEVELOPMENT
In 2001, IdaTech spent approximately $7 million for research and
development of fuel cell technology. IdaTech's research and
development program is focused on the adaptation of its methanol
fuel processor to operate on all commercially important fuels.
Highest priority is given to liquid petroleum gas, natural gas, and
kerosene or diesel fuels.
IdaTech continues its policy of aggressively pursuing patent
protection of its methanol fuel processor in North America, Europe,
South America, Asia, and Australia. The patents issued to IdaTech
address the design and operation of novel fuel reformers and
hydrogen purification devices based on a two-stage hydrogen-
selective metal membrane. Cost reduction through improved designs
and reduced use of expensive materials are useful objectives of
these patents. Additionally, one patent issued to IdaTech in 2001
claims an optimized method for purging hydrogen from the anode
compartment of a PEMFC (Proton Exchange Membrane Fuel Cell) stack so
as to minimize the loss of hydrogen fuel without adversely affecting
the electrical power output from the PEMFC stack. Currently, six-
20 year US patents have been issued to IdaTech. More than 50
pending domestic and foreign patent applications addressing various
aspects of fuel processor design, operation, materials, and
integration with fuel cell stacks.
In 2001, IPC spent approximately $2 million to promote energy
efficiency, including payments of $1 million to the Northwest
Energy Efficiency Alliance and amounts totaling less than $1
million to low-income weatherization programs in Idaho and Oregon.
In addition to increasing the funding level for low-income
weatherization, IPC began a new conservation program late in the
year funded through a conservation credit from the BPA to assist
customers coping with higher winter electricity bills.
During 2001, IPC spent less than $1 million on research and
development through membership in Electric Power Research
Institute (EPRI). EPRI creates science technology solutions for
the global energy and energy service. Some of the subjects of
EPRI projects include: risk based system planning, understanding
green power markets, wind generated electricity and renewable
energy application in distribution generation.
CAPITAL REQUIREMENTS
Capital expenditures of $660 million and debt maturities of $157
million are expected to be paid from 2002 through 2004. IPC utility
construction expenditures exclude AFDC. Over the next three years
internally generated cash and debt issuances are expected to meet
the majority of the funds needed to meet our capital requirements.
Internally generated cash is expected to provide 100 percent in
2002 and an average of 82 percent in 2003 and 2004.
2002 2003-2004
(Millions of dollars)
IPC Utility Capital Expenditures
(excluding AFDC):
Construction Expenditures:
Generating facilities
Hydro $ 15 $ 35
Thermal 13 27
Total generating facilities 28 62
Transmission lines and 18 46
substations
Distribution lines and 57 119
substations
General 21 40
124 267
Long-term debt maturities 27 130
Other 3 9
Total IPC Utility 154 406
Ida-West Capital Expenditures 4 130
IE Capital Expenditures 7 2
IFS Capital Expenditures 59 67
Other 11 15
Total Company $235 $620
IPC has no nuclear involvement and its future construction plans
do not include development of any nuclear generation. IPC's
capital expenditures are primarily for maintaining current
infrastructures and meeting anticipated electricity demands.
Various options that may be available to meet the future energy
requirements of its customers including efficiency improvements on
IPC's generation, transmission and distribution systems and
purchased power and exchange agreements with other utilities or
other power suppliers. IPC will pursue the projects that best
meet its future energy needs.
Ida-West's capital expenditures are primarily for development of
the 273-MW Garnet Energy Facility, which is expected to begin
operation as soon as 2004.
IFS's capital expenditures are primarily for additional
investments in affordable housing projects.
The above estimates are subject to constant revision in light of
changing economic, regulatory and environmental factors and
patterns of conservation. Any additional securities to be sold
will depend upon market conditions and other factors. The Company
will continue to take advantage of any refinancing opportunities
as they become available.
Under the terms of the Indenture relating to IPC's First Mortgage
Bonds, net earnings must be at least two times the annual interest
on all bonds and other equal or senior debt. For the twelve
months ended December 31, 2001, net earnings were 6.44 times.
Additional preferred stock may be issued when earnings for twelve
consecutive months within the preceding fifteen months are at
least equal to 1.75 times the aggregate annual interest
requirements on all debt securities and dividend requirements on
preferred stock. At December 31, 2001, the actual preferred
dividend earnings coverage was 2.79 times. If the dividends on
the shares of Auction Preferred Stock were to reach the maximum
allowed, the preferred dividend earnings coverage would be 2.55
times.
CREDIT RATINGS
All of the Company's publicly traded debt as well as that of IPC
have received investment grade ratings from each of the three
major credit rating agencies. The changes in the energy industry
and the recent bankruptcy of Enron Corp. have caused the rating
agencies to refocus their attention on the credit characteristics
and credit protection measures of industry participants and in
some cases the rating agencies appear to have tightened the
standards for a given rating level. The Company and IPC will
continue to evaluate their capital structures, financing
requirements, competitive strategies and future capital
expenditures to try to maintain investment grade ratings.
However, there is no assurance that these current ratings will
continue for any given period of time or that they will not be
revised by the rating agencies, if, in their respective judgments,
circumstances so warrant. Any downgrade or revision may adversely
affect the market price of the Company or IPC's securities and
serve to increase those companies' cost of capital.
Some collateral agreements in place between IE and its
counterparties include provisions requiring additional margining
in the event of a credit rating downgrade. Credit rating changes
within the investment grade category should not materially impact
the liquidity or financial condition of IE. A credit downgrade
below an investment grade rating could result in additional margin
calls that could have a material negative impact to the liquidity
of IDACORP. The Company believes its existing credit facilities
are adequate to fund these potential liquidity requirements.
ITEM 2. PROPERTIES
IPC's system includes 17 hydroelectric generating plants located
in southern Idaho and eastern Oregon (detailed below), one natural
gas-fired plant and an interest in three coal-fired steam electric
generating plants. The system also includes approximately 4,653
miles of high voltage transmission lines; 21 step-up transmission
substations located at power plants; 18 transmission substations;
7 transmission switching stations; and 208 energized distribution
substations (excludes mobile substations and dispatch centers).
IPC holds licenses under the FPA for 13 hydroelectric projects
from the FERC. These and the other generating stations and their
capacities are listed below:
Maximum
Non-
Coincident Nameplate
Operating Capacity License
Project Capacity kw kW Expiration
Properties Subject to Federal
Licenses:
Lower Salmon 70,000 60,000 1997 (a)
Bliss 80,000 75,000 1998 (a)
Upper Salmon 39,000 34,500 1999 (a)
Shoshone Falls 12,500 12,500 1999 (a)
C J Strike 89,000 82,800 2000 (a)
Upper Malad 9,000 8,270 2004
Lower Malad 15,000 13,500 2004
Brownlee-Oxbow-Hells Canyon 1,398,000 1,166,900 2005
Swan Falls 25,547 25,000 2010
American Falls 112,420 92,340 2025
Cascade 14,000 12,420 2031
Milner 59,448 59,448 2038
Twin Falls 54,300 52,737 2040
Steam and Other Generating
Plants:
Other Hydroelectric 10,400 11,300
Jim Bridger (coal-fired) 706,667 709,617
Valmy (coal-fired) 260,650 260,650
Boardman (coal-fired) 55,200 56,050
Danskin (gas-fired) 100,000 90,000
Salmon (diesel-internal
combustion) 5,500 5,000
(a) Renewed on a year-to-year basis; application for relicense is
pending.
At December 31, 2001, the composite average ages of the principal
parts of IPC's system, based on dollar investment, were:
production plant, 18 years; transmission system and substations,
20 years; and distribution lines and substations, 15 years. IPC
considers its properties to be well maintained and in good
operating condition.
IPC owns in fee all of its principal plants and other important
units of real property, except for portions of certain projects
licensed under the FPA and reservoirs and other easements. IPC's
property is also subject to the lien of its Mortgage and Deed of
Trust and the provisions of its project licenses. In addition,
IPC's property is subject to minor defects common to properties of
such size and character that do not materially impair the value
to, or the use by, IPC of such properties.
Jim Bridger, Valmy and Boardman are jointly owned generating
facilities. IPC's ownership percentages are thirty-three, fifty
and ten, respectively.
Idaho Energy Resources Co. owns a one-third interest in certain
coal leases near the Jim Bridger generating plant in Wyoming from
which coal is mined and supplied to the plant.
Ida-West holds investments in nine operating hydroelectric plants
with a total generating capacity of 45 MW.
Relicensing
As a result of various federal legislative actions and proposals
(such as the Electric Consumers Protection Act of 1986, Energy
Policy Act of 1992, Clean Water Act Reauthorization and Endangered
Species Act Reauthorization), a major issue facing IPC is the
relicensing of its hydro facilities. The relicensing of these
projects is not automatic under federal law. IPC must demonstrate
comprehensive usage of the facilities, that it has been a
conscientious steward of the natural resource entrusted to it, and
that it is in the public interest for IPC to continue to hold the
federal licenses.
IPC is actively pursuing new licenses for 10 of its 17
hydroelectric projects from the FERC. This process will continue
for the next ten to 15 years, depending on environmental issues
and political processes.
The most significant relicensing effort is the Hells Canyon
Complex, which provides over half of IPC's hydro generation
capacity and 40 percent of its total generating capacity.
Presently, IPC is developing its draft license application with
the assistance of a collaborative team made up of individuals
representing state and federal agencies, businesses,
environmental, tribal, customer, local government and local
landowner interests. IPC expects to file the draft license
application in September 2002, with the final application
following in July 2003.
Shoshone Falls, Upper Salmon Falls, Lower Salmon Falls and Bliss
hydroelectric projects are awaiting an Environmental Impact
Statement (EIS) from the federal government, which is necessary
prior to license issuance. IPC completed 64 Additional
Information Requests (AIRs) from the agencies and non-governmental
organizations in early 2000 which, combined with recently filed,
final recommendations, terms and conditions, was used by the
FERC to produce a draft EIS for these projects in January 2002. A
final EIS is expected in August 2002.
IPC filed its application for a new license for the C J Strike
project in November 1998. Similarly, 21 AIRs were issued on this
project and the FERC has noticed that this project is Ready for
Environmental Analysis, which gives the agencies and interested
parties 60 days to provide their final recommendations, terms and
conditions for this project. A draft EIS is expected by June 2002.
The Upper and Lower Malad projects are on schedule to file the new
license application in July 2002. The draft application was sent
to agencies and non-governmental organizations in October 2001.
ITEM 3. LEGAL PROCEEDINGS
IE filed a lawsuit on November 30, 2001 in Idaho State District
Court in and for the County of Ada against Overton Power District
No. 5, a Nevada electric improvement district, for failure to meet
payment obligations under a power contract. The contract provided
for Overton to purchase 40 megawatts of electrical energy per hour
from IE at $88.50 per megawatt hour, from July 1, 2001 through
June 30, 2011. In the contract, Overton agreed to raise its rates
to its customers to the extent necessary to make its payment
obligations to IE under the contract.
IE has asked the Idaho District Court for damages pursuant to the
contract, for a declaration that Overton is not entitled to
renegotiate or terminate the contract and for injunctive relief
requiring Overton to raise rates as agreed.
On December 14, 2001, IE notified Overton that the contract was
terminated due to their failure to meet payment obligations.
IE believes that Overton's breach of contract is completely
without basis and intends to vigorously prosecute this lawsuit.
While the outcome of litigation is never certain, IE believes it
should prevail on the merits. At December 31, 2001, the Company
had a $74 million long-term asset related to the Overton claim.
IE will review the recoverability of the asset on an ongoing
basis.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None
EXECUTIVE OFFICERS OF THE REGISTRANT
The names, ages and positions of all of the executive officers of
the Company are listed below along with their business experience
during the past five years. There are no family relationships
among these officers, nor any arrangement or understanding between
any officer and any other person pursuant to which the officer was
elected.
Name, Age and Position Business Experience During Past Five
(5) Years
Jan B. Packwood, 58 Appointed May 30, 1999. Mr.
President and Chief Packwood was President and Chief
Executive Officer Operating Officer from February 2,
1998 to May 30, 1999.
J. LaMont Keen, 49 Appointed March 1, 2002. Mr. Keen
Executive Vice President was Senior Vice President,
Administration and Chief Financial
Officer from May 5, 1999 to March 1,
2002, Senior Vice President-
Administration, Chief Financial
Officer and Treasurer from March 15,
1999 to May 5, 1999 and Vice
President, Chief Financial Officer
and Treasurer from February 2, 1998
to March 15, 1999.
Richard Riazzi, 47 Appointed March 1, 2002. Mr. Riazzi
Executive Vice President was Senior Vice President, Generation
and Marketing from March 15, 1999 to
March 1, 2002 and Vice President -
Marketing and Sales from January 14,
1999 to March 15, 1999.
Darrel T. Anderson, 43 Appointed March 1, 2002. Mr.
Vice President, Chief Anderson was Vice President, Finance
Financial Officer and and Treasurer from May 5, 1999 to
Treasurer March 1, 2002.
Bryan Kearney, 39 Appointed March 15, 2001.
Vice President and Chief
Information Officer
Gregory W. Panter, 53 Appointed April 1, 2001.
Vice President - Public
Affairs
Robert W. Stahman, 57 Appointed February 2, 1998.
Vice President, General
Counsel and Secretary
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON STOCK AND RELATED
STOCKHOLDER MATTERS
IDACORP's common stock (without par value) is traded on the New
York and Pacific Stock Exchanges. At December 31, 2001, there
were 20,910 holders of record and the year-end stock price was
$40.60 per share.
The following table shows the reported high and low sales price
and dividends paid for the years 2001 and 2000 as supported by the
New York Stock Exchange.
2001 Quarters
Common Stock, without par 1st 2nd 3rd 4th
value:
High $49.38 $41.10 $39.94 $41.14
Low 33.80 34.88 33.55 35.33
Dividends paid per
share (in cents) 46.5 46.5 46.5 46.5
______________________________
2000 Quarters
Common Stock, without par 1st 2nd 3rd 4th
value:
High $53.00 $37.00 $48.69 $51.81
Low 25.94 31.00 32.38 43.38
Dividends paid per
share (in cents) 46.5 46.5 46.5 46.5
ITEM 6. SELECTED FINANCIAL DATA
SUMMARY OF OPERATIONS (millions of dollars except for per share
amounts)
For the Years Ended
December 31, 2001 2000 1999 1998 1997
Operating revenues $5,648 $2,996 $1,433 $1,419 $ 834
Income from operations 243 248 187 181 181
Net income 125 140 91 89 87
Earnings per average
share outstanding
(basic and diluted) 3.35 3.72 2.43 2.37 2.32
Dividends declared per 1.86 1.86 1.86 1.86 1.86
share
At December 31,
Total long-term debt* 843 864 822 816 746
Total assets 3,642 4,040 2,640 2,457 2,452
*Excludes amount due within one year.
The above data should be read in conjunction with the consolidated
financial statements and notes to consolidated financial
statements included in this Form 10-K.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
INTRODUCTION
In Management's Discussion and Analysis we explain the general
financial condition and results of operations of IDACORP, Inc. and
its subsidiaries (IDACORP or the Company). IDACORP is a holding
company formed in 1998 and is the parent of Idaho Power Company
(IPC), IDACORP Energy (IE), and several other entities.
IPC is an electric utility with a service territory covering over
20,000 square miles, primarily in southern Idaho, and eastern
Oregon. IPC is the parent of Idaho Energy Resources Co., a joint
venturer in Bridger Coal Company, which supplies coal to IPC's Jim
Bridger generating plant.
IE markets electricity and natural gas, and offers risk management
and asset optimization services, to wholesale customers in 31 states
and two Canadian provinces. In June 2001, IPC transferred its non-
utility energy marketing operations to IE.
IDACORP's other operating subsidiaries include:
Ida-West Energy (Ida-West) - independent power projects
development and management;
IdaTech - developer of integrated fuel cell systems;
IDACORP Financial Services (IFS) - affordable housing and other
real estate investments;
Velocitus - commercial and residential Internet service
provider;
IDACOMM - provider of telecommunications services.
As you read Management's Discussion and Analysis, it may be helpful
to refer to our Consolidated Statements of Income which present our
results of operations for the years ended December 31, 2001, 2000
and 1999.
FORWARD-LOOKING INFORMATION
In connection with the safe harbor provisions of the Private
Securities Litigation Reform Act of 1995 (Reform Act), we are hereby
filing cautionary statements identifying important factors that
could cause our actual results to differ materially from those
projected in forward-looking statements (as such term is defined in
the Reform Act) made by or on behalf of the Company in this Annual
Report, any quarterly report on Form 10-Q, in presentations, in
response to questions or otherwise. Any statements that express, or
involve discussions as to expectations, beliefs, plans, objectives,
assumptions or future events or performance (often, but not always,
through the use of words or phrases such as "anticipates,"
"believes," "estimates," "expects," "intends," "plans," "predicts,"
"projects," "will likely result," "will continue," or similar
expressions) are not statements of historical facts and may be
forward-looking. Forward-looking statements involve estimates,
assumptions, and uncertainties and are qualified in their entirety
by reference to, and are accompanied by, the following important
factors, which are difficult to predict, contain uncertainties, are
beyond our control and may cause actual results to differ materially
from those contained in forward-looking statements:
prevailing governmental policies and regulatory actions,
including those of the Federal Energy Regulatory Commission
(FERC), the Idaho Public Utilities Commission (IPUC), the
Oregon Public Utilities Commission (OPUC), and the Public
Utilities Commission of Nevada (PUCN), with respect to allowed
rates of return, industry and rate structure, acquisition and
disposal of assets and facilities, operation and construction
of plant facilities, recovery of purchased power and other
capital investments, and present or prospective wholesale and
retail competition (including but not limited to retail
wheeling and transmission costs);
the current energy situation in the western United States;
economic and geographic factors including political and
economic risks;
changes in and compliance with environmental and safety laws
and policies;
weather conditions;
population growth rates and demographic patterns;
competition for retail and wholesale customers;
pricing and transportation of commodities;
market demand, including structural market changes;
changes in tax rates or policies or in rates of inflation;
changes in project costs;
unanticipated changes in operating expenses and capital
expenditures;
capital market conditions;
competition for new energy development opportunities; and
legal and administrative proceedings (whether civil or
criminal) and settlements that influence the business and
profitability of the Company.
Any forward-looking statement speaks only as of the date on which
such statement is made. New factors emerge from time to time and it
is not possible for management to predict all such factors, nor can
it assess the impact of any such factor on the business or the
extent to which any factor, or combination of factors, may cause
results to differ materially from those contained in any forward-
looking statement.
RESULTS OF OPERATIONS
In this section we discuss our earnings and the factors that
affected them, beginning with a general overview and then discussing
results for each of our operating segments.
Earnings per share of
common stock
2001 2000 1999
Utility operations $0.60 $1.97 $2.00
Energy marketing 2.87 1.58 0.34
Other operations (0.12) 0.17 0.09
Total earnings per
share $3.35 $3.72 $2.43
Return on year-end
common equity 14.4% 17.0% 12.1%
High wholesale energy prices and a severe drought had a negative
effect on utility operations from 2000 to 2001. Of the $1.37
decrease from 2000, $0.70 cents per share is attributable to
increases in power supply expenses absorbed by IPC and $0.18 per
share is due to the write-off of amounts disallowed in IPC's 2001
power cost adjustment (PCA). Additional increases in operating
expenses for maintenance, depreciation, interest and customer
expenses decreased earnings by approximately $0.34 per share.
The decrease in (earning per share) EPS from utility operations from
1999 to 2000 is predominantly the result of increased net power
supply costs of $69 million, due to declining hydroelectric
generating conditions and increased market prices for purchased
power. These costs were partially offset by a $49 million increase
in general business revenue resulting from rate increases, customer
growth, and weather conditions. In 2000 we recorded a $7 million
pension credit and in 1999 we recorded a $9 million reduction to
income for shared revenue (see "Regulatory Issues - Regulatory
Settlement").
EPS from energy marketing increased $1.29 per share in 2001 and
$1.24 per share in 2000. This strong performance was driven
primarily by increased structured origination activities, continued
price volatility and increased volumes of transactions. The annual
total volume of settled power sales increased 49 percent to 34.9
million megawatt-hours (MWh) in 2001 and increased 63 percent to
23.5 million MWh in 2000.
EPS from other operations decreased in 2001 and increased in 2000,
principally because of a gain recorded on the sale in March 2000 of
the Hermiston Power Project. This gain contributed approximately
$0.22 per share in 2000. Increased operating losses at recently
acquired subsidiaries was the primary source of the rest of the
change in EPS from other operations in both 2001 and 2000.
UTILITY OPERATIONS
This section discusses IPC's utility operations, which are subject
to regulation by, among others, the state public utility commissions
of Idaho, Oregon and Nevada and by the FERC. Before we discuss the
changes in income from our utility operations, we'll describe these
operations and the significant factors that influenced them in 2001
and 2000.
The main catalysts for the changes that occurred in our utility
operations were high wholesale energy prices and the drought in the
Northwest. In late 2000 and early 2001, prices for electricity in
the wholesale markets became highly volatile, reaching unprecedented
levels.
Faced with soaring demand, exorbitant prices and very little water
to produce power, we set in motion a number of measures to decrease
our reliance on the wholesale power markets, by decreasing demand
and increasing our generating capabilities. Some of these measures
were:
The IPUC approved a two-year agreement through which we
compensate our largest industrial customer, Astaris, for
reducing its load by 50 MW.
The IPUC and OPUC approved programs that compensated irrigation
customers capable of reducing usage by at least 100 MWh.
As part of the May 2001 PCA, the IPUC required IPC to implement
a tiered rate structure for Idaho residential customers. This
rate structure increases rates as a customer's usage increases.
In September 2001 we placed in service Danskin Power Plant, a
90-MW natural gas-fired combustion turbine plant, located near
Mountain Home, Idaho.
Mobile generators with total generating capacity of 40 MW were
sited at various locations in Boise during portions of the
year.
In May 2001 we made the largest filing in the nine years that our
PCA mechanism has been in effect, seeking recovery of $227 million,
96 percent of which we are now recovering.
IPC owns and operates 17 hydroelectric power plants and one natural
gas-fired plant and shares ownership in three coal-fired generating
plants. The following table presents IPC's system generation for
the last three years:
MWhs Percent of total
(in thousands) generation
2001 2000 1999 2001 2000 1999
Hydroelectric 5,638 8,500 10,652 43% 52% 59%
Thermal 7,622 7,701 7,266 57 48 41
Total system
generation 13,260 16,201 17,918 100% 100% 100%
As the table shows, we rely on low-cost hydroelectric plants for a
significant portion of our generation. Over the last ten years,
hydro generation has averaged 8.7 million MWh, 57 percent of our
total generation.
The amounts of electricity we are able to generate from these hydro
plants depend on a number of factors, primarily snowpack in the
mountains above our hydro facilities, reservoir storage, and
streamflow requirements. When these factors are favorable, we can
generate more electricity using our hydroelectric plants. When these
factors are unfavorable, we must increase our reliance on more
expensive thermal plants and purchased power.
As of this writing, Snake River Basin snowpack numbers offer the
promise of improved streamflows. Our mid-February 2002 accumulations
were 84 percent of normal, compared to 51 percent at the same time a
year earlier. Even though snowpack is closer to normal, reservoir
storage is not, meaning hydro conditions will not fully return to
normal in 2002.
Regulatory authorities determine the rates we charge to our general
business customers. Approximately 95 percent of our general
business revenue and sales come from customers in the state of
Idaho. The rates we charge these customers are adjusted annually by
a PCA mechanism. The PCA adjusts rates to reflect the changes in
costs incurred by IPC to supply power. Throughout the year, we
compare our actual power supply costs to the amounts we are
recovering in rates. Most, but not all, of this difference is
deferred and included in the calculation of rates for future years.
The primary influences on electricity sales volumes are weather and
economic conditions. Generally, extreme temperatures increase sales
to customers, who use electricity for cooling and heating, and
moderate temperatures decrease sales. Precipitation levels during
the growing season affect sales to customers who use electricity to
operate irrigation pumps. Increased precipitation reduces
electricity usage by these customers. In addition, in 2001 we put
in place several demand management programs designed to reduce
energy consumption by our customers. Finally, the significant rate
increases implemented in this year's PCA have reduced demand.
General business customer growth continued, with 2.5 percent and 2.4
percent annual increases over the last two years in our Idaho-Oregon
service territory.
The following table summarizes our utility operating results. Each
line is analyzed in more detail below.
2000-2001 1999-2000
Increase Increase
2001 2000 (Decrease) 1999 (Decrease)
(in millions of dollars)
Operating revenues:
General business $ 650 $ 565 $ 85 $ 516 $ 49
Off-system 220 230 (10) 120 110
Other 44 42 2 24 18
Total operating
revenues 914 837 77 660 177
Operating expenses:
Purchased power 584 399 185 106 293
Fuel 98 94 4 87 7
PCA (176) (121) (55) (1) (120)
Other operating
expenses 318 296 22 296 -
Total operating
expenses 824 668 156 488 180
Operating income $ 90 $ 169 $ (79) $ 172 $ (3)
General Business Revenue
The following table presents IPC's general business revenues and
volumes for the last three years:
Revenues Volumes
(in millions of (in thousands of
dollars) MWh)
2001 2000 1999 2001 2000 1999
Residential $ 260 $ 225 $ 214 4,307 4,393 4,200
Commercial 164 132 123 3,380 3,404 3,194
Industrial 154 133 117 3,925 4,808 4,666
Irrigation 72 75 62 1,419 1,993 1,706
Total $ 650 $ 565 $ 516 13,031 14,598 13,766
As mentioned above, our general business revenue is dependent on
many factors, including the number of customers we serve, the rates
we charge, and weather conditions.
2001 vs. 2000: In 2001, the following factors influenced the 15.0
percent increase in general business revenue:
Increased average rates, resulting from the PCA, increased
revenue $137 million. We discuss the PCA in more detail below
in "Regulatory Issues - Power Cost Adjustment";
A 2.5 percent increase in general business customers increased
revenue $16 million;
Conservation programs, including irrigation and large customer
buybacks, and other usage factors, decreased energy
consumption, reducing revenues $67 million.
2000 vs. 1999: The 9.5 percent increase in general business
revenues is due to the following factors:
Increased average rates, resulting from the PCA and special-
contract customers, increased revenues $17 million;
Increased usage per customer, resulting from weather conditions
and other factors, increased revenues $26 million. Decreased
precipitation during the growing season increased sales to
irrigation customers, and hotter summer and colder winter
temperatures increased sales to the other customer classes;
Our average number of customers increased 2.4 percent over
1999, increasing revenue $6 million.
Off-system sales
Off-system sales consist primarily of long-term sales contracts and
opportunity sales of surplus system energy.
$ (in millions) MWh (in thousands) Revenue per MWh
2001 2000 1999 2001 2000 1999 2001 2000 1999
$220 $230 $120 2,387 4,529 5,924 $92.14 $50.78 $20.22
2001 vs. 2000: Off-system sales decreased due principally to a 47
percent decrease in volume sold, a result of poor hydro generating
conditions. The volume decrease was partially offset by an 81
percent increase in price per MWh.
2000 vs. 1999: Off-system sales increased due predominantly to
significant increases in prices for surplus system energy, which
increased our average revenue per MWh by over 150 percent. A 24
percent decrease in volumes of electricity sold, due to decreased
availability, partially offset the increase in market prices.
Power Supply
The power supply components of operating income include off-system
sales (described and analyzed above) and purchased power, fuel and
PCA expenses (analyzed below).
The impact of the changes in net power supply costs was an increase
in net power supply expense of $144 million in 2001 and $70 million
in 2000.
Purchased power
$ (in millions) MWh (in thousands) Cost per MWh
2001 2000 1999 2001 2000 1999 2001 2000 1999
$584 $399 $106 3,445 4,311 3,127 $169.52 $92.47 $34.01
2001 vs. 2000: Purchased power expenses increased $185 million in
2001. Contributing to these results are a number of factors,
including wholesale market conditions, and $132 million of
irrigation and Astaris load reduction program costs.
2000 vs. 1999: Purchased power expenses increased $293 million in
2000 due to major increases in prices in the energy markets, and to
increased volumes purchased. The increase in volumes was
necessitated by decreased generation at our hydroelectric plants and
increased customer demand.
Fuel expense
$ (in millions) Thermal MWh generated
(in thousands)
2001 2000 1999 2001 2000 1999
$ 98 $ 94 $ 87 7,622 7,701 7,266
2001 vs. 2000: Expenses increased in 2001, despite decreased
generation. Average coal prices increased, and our new 90-MW gas-
fired plant went on-line in September 2001.
2000 vs. 1999: Fuel expenses increased by $7 million in 2000, due
primarily to increased generation at our coal-fired plants,
necessitated by decreased generation at our hydroelectric plants and
increased customer demand.
Power Cost Adjustment
The PCA component of expenses is related to IPC's PCA regulatory
mechanism. The PCA mechanism increases expenses when power supply
costs are below forecast, and decreases expenses when power supply
costs are above forecast. We discuss the PCA in more detail in
"Regulatory Issues - Power Cost Adjustment."
2001 vs. 2000: The PCA credit increased $55 million in 2001, due to
2001's power supply costs being greater than forecast, a result of
higher prices and greater volumes of purchased power and the costs
related to the load reduction programs that we introduced this year.
2000 vs. 1999: The PCA expense was a credit of $121 million in
2000, due predominantly to the considerable increases in purchased
power costs not anticipated in our 2000-2001 rate year forecast.
In 1999, actual power supply costs were near forecast, causing the
PCA component of expense to be minimal.
Other Utility Operating Expenses
2001 vs. 2000: Other operations and maintenance expenses increased
$22 million in 2001. The most significant changes were:
Depreciation and amortization expenses increased $7 million,
due primarily to plant additions;
Costs at thermal plants increased a total of $7 million,
primarily due to unscheduled maintenance;
Leased diesel generators to protect against electricity supply
shortages, totaled $5 million;
Operating costs related to the implementation of our new
customer accounting system, and write-offs of uncollectible
accounts increased $4 million.
2000 vs. 1999: Other operations and maintenance expenses in 2000
were substantially unchanged from 1999. The most significant
changes were:
Pension expenses decreased $7 million due to favorable returns
on plan assets;
Distribution line maintenance expenses increased $4 million,
primarily due to increased tree clearing and pole maintenance;
Operating costs related to our customer accounting system
increased $2 million;
Depreciation expenses increased $2 million, primarily due to
plant additions.
ENERGY MARKETING
IE markets electricity and natural gas, and offers risk management
and asset optimization services, to wholesale customers in 31 states
and two Canadian provinces. IE has offices in Boise, Idaho and
Houston, Texas and employs approximately 120 people. Our energy
marketing strategy has produced increasingly positive results
through growing the volume of energy delivered, expanding the
geographic area in which we do business, and capitalizing on the
recent high volatility of energy prices. While we continue to be
active in the natural gas markets, our business expansion has
primarily been driven from three interdependent strategies in the
electricity markets. First, we use our expertise in the physical
power system within the western United States to purchase the rights
to strategic transmission. While we have no obligation to renew
these rights annually, many of them can be extended indefinitely,
barring any regulatory changes, giving us the ability to assess the
value of the rights on an annual basis before renewal. The second
piece of our strategy is to buy and sell energy around these
contractual transmission assets and take advantage of market price
movements between regions while limiting our market risk. Third, we
use our knowledge of the physical system coupled with our risk
management expertise to create customized, or structured, energy
solutions for end-use customers.
Additionally, IE offers asset management services to utilities and
other regulated energy providers. One such agreement is with our
affiliate, IPC. Concurrent with the June 2001 transfer of the non-
utility electricity marketing business from IPC to IE, IE and IPC
have entered into an Electricity Supply Management Services
Agreement (Agreement). IPC received approval of the Agreement from
the IPUC, the OPUC and the FERC. Under the Agreement, IPC will
continue to own, operate and maintain its electric generating
equipment and transmission facilities (system resources) and be
responsible for system reliability. IE will manage and dispatch the
system resources to balance generation and load within the IPC
operating area.
Operating income for IE was $177 million in 2001 compared to $95
million in 2000. Gross margin for 2001 was $243 million, $92 million
of which is unrealized gains related to the change in value of our
forward position. On a cumulative basis, we anticipate that
approximately 39 percent of these unrealized forward positions
recorded at year end 2001 will be settled by the end of 2002, 57
percent settled by the end of 2003 and 71 percent settled by the end
of 2004. All forward positions at December 31, 2001 should be
settled within 10 years. Changes in market conditions in future
periods could substantially change the amounts of gain or loss
ultimately realized upon settlement of the contracts.
Revenues
We now report on a gross revenue and gross expense basis, rather
than the netting method previously used. Settled physical sales now
are reported as revenue and settled physical purchases are reported
as operating expenses. Both revenues and expenses have been
reclassified to reflect this change.
This change has been made since the power marketing operation was
consolidated under IE. When power marketing was housed within IPC,
the gross method of reporting energy marketing revenues would have a
caused a potential distortion to the reported utility results.
Therefore, we elected to report energy marketing revenues on a net
basis. Now that power marketing is fully separated from the
utility, the gross presentation provides a more clear comparison of
our marketing and trading activities in relationship to similar
companies.
The following table presents our energy marketing revenues and
volumes (including intersegment transactions) for the last three
years:
2000-2001 1999-2000
Increase Increase
2001 2000 (Decrease) 1999 (Decrease)
(in millions of dollars)
Operating revenues:
Electricity $ 4,531 $ 2,191 $ 2,340 $ 594 $ 1,597
Gas 362 271 91 278 (7)
Total operating
revenues $ 4,893 $ 2,462 $ 2,431 $ 872 $ 1,590
Operating volumes
(settled):
Electricity
(MWh's) 34,936,951 23,518,484 11,418,467 14,433,650 9,084,834
Gas (mmbtu's) 97,327,432 80,728,530 16,598,902 141,432,755 (60,704,225)
2001 vs. 2000: The 99 percent increase in 2001 energy marketing
revenue is due primarily to increased volumes and prices. Settled
physical electricity sales increased 49 percent. Electricity prices
in 2001 were, on average, nearly 40 percent higher than in 2000.
2000 vs. 1999: The 182 percent increase in 2000 energy marketing
revenue is also due primarily to increased volumes and prices.
Settled physical electricity sales increased 63 percent.
Electricity prices in 2000 were, on average, 125 percent higher than
in 1999.
Operating Expenses
The following table presents our energy marketing operating expenses
for the last three years:
2000-2001 1999-2000
Increase Increase
2001 2000 (Decrease) 1999 (Decrease)
(in millions of dollars)
Electricity $ 4,360 $2,098 $ 2,262 $571 $ 1,527
Gas 356 269 87 279 (10)
Total operating
expenses $ 4,716 $2,367 $ 2,349 $850 $ 1,517
2001 vs. 2000: The 99 percent increase in operating expenses is
also due primarily to the increase in volumes and prices.
2000 vs. 1999: The 178 percent increase for the year is due
primarily to the increase in volumes and prices and also to an
increase in the allowance for bad debt. The expense related to bad
debt reserves in 2000 was $22 million compared to $0 in 1999. These
reserves are related to trading activities conducted with California
entities in 2000.
Contracts Accounted for at Fair Value
The commodity transactions entered into by IE are classified as
energy trading contracts, or derivatives. These contracts are
carried on the balance sheet at fair value. This accounting
treatment is also referred to as mark-to-market accounting. Mark-to-
market accounting can create a disconnect between recorded earnings
and realized cash flow. Marking a contract to market consists of
reevaluating the market value of the entire term of the contract at
each reporting period and reflecting the resulting gain or loss of
value in earnings for the period. This change in value represents
the difference between the contract price and the current market
value of the contract. The change in market value of the contract
could result in large gains or losses recorded in earnings at each
subsequent reporting period unless there are offsetting changes in
value of hedge contracts. The gain or loss in income generated from
the change in market value of the energy trading contracts is a non-
cash event. If these contracts are held to maturity, the cash flow
from the contracts, and their hedges, is realized over the life of
the contract.
When determining the fair value of our marketing and trading
contracts, we use actively quoted prices for contracts with similar
terms as the quoted price, including specific delivery points and
maturities. To determine fair value of contracts with terms that are
not consistent with actively quoted prices, we use (when available)
prices provided by other external sources. When prices from external
sources are not available, we determine prices by using internal
pricing models that incorporate available current and historical
pricing information. Finally, we adjust the fair market value of our
contracts for the impact of market depth and liquidity, potential
model error, and expected credit losses at the counterparty level.
The following table details the gross margin booked from our
marketing operations over the last three years:
2001 2000 1999
(in millions of dollars)
Gross Margin:
Realized or
otherwise settled $ 150 $ 181 $ 28
Unrealized 93 (35) 4
Total gross
margin $ 243 $ 146 $ 32
At year-end 2001, 69 percent of the credit exposure related to our
unrealized positions is with investment grade couterparties. Less
than 0.5 percent is with non-investment grade counterparties. The
remaining 31 percent of year-end credit exposure is with non-rated
counterparties. The majority of the non-rated entities are
municipalities, public utility districts and electric cooperatives.
The change in net fair value (energy marketing assets less energy
marketing liabilities) between year-end 2000 and year-end 2001 is
explained as follows (in millions of dollars):
Net fair value of contracts outstanding as of
12/31/2000 $ (3)
Contracts realized or otherwise settled during
the period (150)
Changes in net fair values attributable to
changes in valuation techniques and assumptions 7
Changes in net fair value attributable to
market prices and other market changes 284
Net fair value of contracts outstanding as of
12/31/2001 $ 138
Net fair value at year-end 2001 disaggregated by source of fair
value and maturity of contracts:
Maturity Maturity
Source of less than Maturity Maturity in excess of Grand
Fair Value 1 year 1-3 years 4-5 years 5 years Total
(in millions of dollars)
Prices actively
quoted $ 34 $ 37 $ 3 $ 0 $ 74
Prices provided
by other external
sources 16 27 (1) 6 48
Prices based on
models and other
valuation
methods 19 (5) 1 1 16
Total $ 69 $ 59 $ 3 $ 7 $ 138
Prices actively quoted are quoted daily by brokers and trading
exchanges such as NYMEX, TFS, Intercontinental, and Bloomberg. The
time horizon is January 2002 through December 2006. Products include
physical, financial, swap, interest rate, index, and basis for both
natural gas and heavy load power.
Prices provided by other external sources are quoted periodically by
brokers and trading exchanges such as TFS, APB, Prebon,
Intercontinental, and Bloomberg. The time horizon is January 2002
through December 2010. Products include physical, financial, swap,
index, and basis for both natural gas and heavy and light load
power.
Prices derived from models and other valuation methods incorporate
available current and historical pricing information. The time
horizon is January 2002 through December 2009. Products include
transmission, options, and ancillary services related to heavy and
light load power.
OTHER OPERATIONS
Other operations include the results of operations of our
diversified subsidiaries, including IDACOMM, Velocitus, Ida-West,
IdaTech, IFS, and Applied Power Company (APC) (sold in January
2001).
In August 2000, we formed IDACOMM, Inc. to provide integrated
communication services to business customers throughout the West,
using fiber optic network technology. Also, in August 2000, we
acquired a controlling interest in Velocitus (formerly Rocky
Mountain Communications, Inc.), a Boise, Idaho-based Internet
service provider. Since the acquisition, Velocitus launched a new
service-Velocitus Broadband, which emphasizes the use of fixed
wireless technology, allowing for rapid deployment of high-speed
connectivity for business customers. Velocitus currently serves
more than 25,000 subscribers of traditional and high-speed Internet
access services.
Ida-West develops, acquires, owns and manages electric power
generation projects.
In December 2001, IdaTech, a majority owned subsidiary of IDACORP,
continued to make progress by delivering nine second generation fuel
cell systems, of the first block of 50 units, to the Bonneville
Power Administration (BPA) for field testing. IdaTech continues to
develop and seek business partners in North America, Europe, and
Asia to help support the commercialization of its fuel processor and
fuel cell systems. IdaTech has delivered fuel processors and fuel
cell systems to companies in those three continents for evaluation
and testing in various field applications.
IFS, a wholly owned subsidiary of IDACORP, makes investments in
projects that provide affordable housing tax credits and historic
tax credits.
In January 2001, we sold APC to Schott Corp. APC is a manufacturer,
supplier and distributor of solar photovoltaic systems. IDACORP
originally acquired APC in 1996.
Revenues
2001 vs. 2000: Other operations revenues decreased $10 million in
2001 due primarily to the sale of APC. APC generated revenues of
$16 million in 2000. This decrease was partially offset by a $5
million increase in sales at Velocitus, which was acquired in August
2000.
2000 vs. 1999: Other operations revenues decreased $4 million in
2000 due primarily to reduced sales made at APC.
Expenses
2001 vs. 2000: Other operations expenses decreased $2 million in
2001 due primarily to the sale of APC. APC incurred $17 million of
expenses in 2000. Increased expenses related to product development
activities at IdaTech ($8 million) and Velocitus ($7 million) offset
the decrease from APC.
2000 vs. 1999: Other operations expenses increased $5 million in
2000 due primarily to $5 million of increases from both Velocitus,
(acquired in August 2000), and from increased activities at IdaTech,
offset by a $5 million reduction in expenses at APC.
OTHER INCOME AND EXPENSES
Other Income
2001 vs. 2000: Other income decreased $7 million in 2001, due
primarily to the sale in 2000 of our interest in the Hermiston Power
Project, a 536-MW, gas-fired cogeneration project to be located near
Hermiston, Oregon. Ida-West was responsible for managing all
permitting and development activities relating to the project since
its inception in 1993. We recorded a pre-tax gain of $14 million on
this transaction in 2000. This decrease was partially offset by a
gain recognized in 2001 related to the early redemption by the
Friant Power Authority of outstanding bonds held by Ida-West.
2000 vs. 1999: Other income increased $13 million in 2000 due
primarily to the sale of our interest in the Hermiston Power
Project. We recorded a pre-tax gain of $14 million on this
transaction.
Interest Expense and Other
Interest expense and other increased $9 million in 2001 and was
unchanged in 2000. The increase in 2001 is predominantly the result
of higher short-term debt balances to finance power purchased for
IPC's system, partially offset by significant decreases in borrowing
rates. Our average short-term debt in 2001 was $232 million,
compared to $36 million in 2000.
Income taxes
Fluctuations in income tax expense result primarily from changes in
net income before taxes.
LIQUIDITY AND CAPITAL RESOURCES
Cash Flow
Operating cash flows and working capital levels declined in 2001,
predominantly due to the growth in our PCA regulatory asset balance,
reflecting increased power supply expenditures that we have not yet
recovered through PCA rate adjustments. Our net cash generated from
operations totaled $356 million for the three-year period 1999-2001.
After deducting common dividends of $210 million, net cash
generation from operations provided approximately $146 million for
our construction program and other capital requirements. Internal
cash generation after dividends provided 42 percent of our total
capital requirements in 2000 and 114 percent in 1999.
We forecast that internal cash generation after dividends will
provide approximately 100 percent of total capital requirements in
2002 and 82 percent during the two-year period 2003-2004. We expect
to continue financing our utility construction program and other
capital requirements with both internally generated funds and, as
discussed below, externally financed capital.
The following table presents IDACORP's total contractual cash
obligations:
2002 2003 2004 2005 2006 Thereafter
(in millions of dollars)
Utility long-
term debt $27 $80 $50 $60 $ - $612
Other long-
term debt 9 9 9 8 6 9
Fuel supply
contracts 38 33 30 27 19 11
At December 31, 2001, IPC had regulatory authority to incur up to
$500 million of short-term indebtedness. At December 31, 2001,
IPC's short-term borrowing totaled $282 million, consisting of $100
million of floating rate notes and $182 million of commercial paper,
compared to $60 million of commercial paper at December 31, 2000.
The increase is primarily a result of the unrecovered power supply
expenditures mentioned above.
We have bank line of credit facilities established at both IPC and
IDACORP.
IPC has a $165 million facility that expires April 26, 2002 and a
$120 million facility that expires April 18, 2002. Under these
facilities IPC pays a facility fee on the commitment, quarterly in
arrears, based on IPC's First Mortgage Bond Rating. IPC's
commercial paper may be issued up to the amount supported by the
bank credit facilities.
IDACORP has a $375 million facility that expires on April 15, 2002
and a $50 million facility that expires on April 20, 2002. Under
these facilities we pay a facility fee on the commitment, quarterly
in arrears, based on IDACORP's senior unsecured long-term debt
rating. Commercial paper may be issued up to the amounts supported
by the bank credit facilities. At December 31, 2001, IDACORP's
short-term borrowing totaled $81 million, compared to $61 million at
December 31, 2000.
IDACORP is currently in the process of renewing its credit lines at
both IDACORP (for $500 million) and IPC (for $200 million) with
closing anticipated in March 2002.
Credit Ratings
All of the Company's publicly traded debt as well as that of IPC
have received investment grade ratings from each of the three
major credit rating agencies. The changes in the energy industry
and the recent bankruptcy of Enron Corp. have caused the rating
agencies to refocus their attention on the credit characteristics
and credit protection measures of industry participants and in
some cases the rating agencies appear to have tightened the
standards for a given rating level. The Company and IPC will
continue to evaluate their capital structures, financing
requirements, competitive strategies and future capital
expenditures to try to maintain investment grade ratings.
However, there is no assurance that these current ratings will
continue for any given period of time or that they will not be
revised by the rating agencies, if, in their respective judgments,
circumstances so warrant. Any downgrade or revision may adversely
affect the market price of the Company or IPC's securities and
serve to increase those companies' cost of capital.
Some collateral agreements in place between IE and its
counterparties include provisions requiring additional margining
in the event of a credit rating downgrade. Credit rating changes
within the investment grade category should not materially impact
the liquidity or financial condition of IE. A credit downgrade
below an investment grade rating could result in additional margin
calls that could have a material negative impact to the liquidity
of IDACORP. The Company believes its existing credit facilities
are adequate to fund these potential liquidity requirements.
Working Capital
Net working capital (current assets less current liabilities)
decreased approximately $213 million from December 31, 2000 to
December 31, 2001. The most significant changes were in notes
payable and energy marketing assets and liabilities.
The primary cause of the increase in notes payable is power supply
expenditures. We discuss recovery of these costs in "Regulatory
Issues" later in the MD&A.
Energy marketing assets and liabilities reflect the fair value of
energy marketing contracts as of the reporting date. The fair value
of these contracts is unrealized and therefore does not necessarily
indicate a current source or use of funds. The decreases in energy
marketing assets and liabilities from 2000 to 2001 is primarily a
reflection of significantly lower market prices at December 31,
2001, than in the prior year. Additional netting agreements between
IE and its counterparties also contributed to a reduction in the
energy assets and liabilities. Finally, an increase in posted
collateral supporting our energy trading contracts further reduced
the energy trading liability.
Construction Program
Our consolidated cash construction expenditures totaled $180 million
in 2001, $140 million in 2000, and $111 million in 1999.
Approximately 25 percent of these expenditures were for generation
facilities, 19 percent for transmission facilities, 30 percent for
distribution facilities, and 26 percent for general plant and
equipment.
We estimate that our cash construction and acquisition programs will
require the following amounts over the next three years. These
estimates are subject to revision in light of changing economic,
regulatory, environmental, and conservation factors.
2002 2003-2004
(in millions of dollars)
Utility $124 $267
Energy marketing 7 2
Other 63 197
Total $194 $466
Financing Program
Our consolidated capital structure fluctuated slightly during the
three-year period, with common equity ending at 48 percent,
preferred stock of IPC 6 percent, and long-term debt 46 percent at
December 31, 2001.
At December 31, 2001, IPC also had $100 million of floating rate
notes outstanding, payable on September 1, 2002 included in notes
payable.
We are proceeding with our plans to issue equity and debt securities
this year. The equity issuance could take the form of common
equity, mandatorily redeemable equity securities, or both. We are
also planning to raise additional debt to provide balance in the
capital that we raise. The Company is still reviewing its options
with regard to type of securities, size and timing, but we expect
that the capital will be raised in the first half of 2002.
In February 2002, IPC notified holders of its $50 million 8 3/4%
Series First Mortgage Bonds due 2027 of its intent to redeem
these bonds on March 15, 2002.
IDACORP currently has a $300 million shelf registration statement
that can be used for the issuance of unsecured debt (including
medium-term notes) and preferred or common stock. At December 31,
2001, none had been issued.
In March 2000 IPC filed a $200 million shelf registration statement
that could be used for first mortgage bonds (including medium-term
notes), unsecured debt, or preferred stock. In December 2000, $80
million of Secured Medium-Term Notes were issued by IPC. Proceeds
from this issuance were used in January 2001 for the early
redemption of $75 million of First Mortgage Bonds originally due in
2021. In March 2001, IPC issued $120 million of Secured Medium-Term
Notes, with the proceeds used to reduce short-term borrowing
incurred in support of ongoing long-term construction requirements.
In August 2001, IPC filed a $200 million shelf registration that can
be used for first mortgage bonds (including medium-term notes),
unsecured debt, or preferred stock. At December 31, 2001, no
amounts have been issued.
In August 2001, $25 million of First Mortgage Bonds due in 2031 were
redeemed early.
In April 2000, at our request, the American Falls Reservoir District
issued its American Falls Refunding Replacement Dam Bonds, Series
2000. Proceeds from issuance of these bonds, in the aggregate
amount of $20 million, were used to refund the same amount of bonds
dated May 1, 1990. IPC has guaranteed repayment of these bonds.
In May 2000, $4 million of tax-exempt Pollution Control Revenue
Refunding Bonds were issued by Port of Morrow, Oregon. Proceeds
were used to refund in August 2000 the same amount of Pollution
Control Revenue Bonds, Series 1978.
CURRENT ISSUES
In this section we address a number of other issues that affect or
could affect our operations.
California Energy Situation
As a component of IPC's non-utility energy trading in the state of
California, IPC, in January 1999, entered into a participation
agreement with the California Power Exchange (CalPX), a California
non-profit public benefit corporation. The CalPX, at that time,
operated a wholesale electricity market in California by acting as a
clearinghouse through which electricity was bought and sold.
Pursuant to the participation agreement, IPC could sell power to the
CalPX under the terms and conditions of the CalPX Tariff. Under the
participation agreement, if a participant in the CalPX exchange
defaults on a payment to the exchange, the other participants are
required to pay their allocated share of the default amount to the
exchange. The allocated shares are based upon the level of trading
activity, which includes both power sales and purchases, of each
participant during the preceding three-month period.
On January 18, 2001, the CalPX sent IPC an invoice for $2.2 million
- - a "default share invoice" - as a result of an alleged Southern
California Edison (SCE) payment default of $214.5 million for power
purchases. IPC made this payment. On January 24, 2001, IPC
terminated the participation agreement. On February 8, 2001, the
CalPX sent a further invoice for $5.2 million, due February 20,
2001, as a result of alleged payment defaults by SCE, Pacific Gas
and Electric Company (PG&E), and others. However, because the CalPX
owed IPC $11.3 million for power sold to the CalPX in November and
December 2000, IPC did not pay the February 8th invoice. IPC
essentially discontinued energy trading with California entities in
December 2000. IPC believes that the default invoices were not
proper and that IPC owes no further amounts to the CalPX. IPC has
pursued all available remedies in its efforts to collect amounts
owed to it by the CalPX.
On February 20, 2001, IPC filed a petition with FERC to intervene in
a proceeding which requested the FERC to suspend the use of the
CalPX charge back methodology and provides for further oversight in
the CalPX's implementation of its default mitigation procedures.
A preliminary injunction was granted by a Federal Jud